Forming a wellbore casing while simultaneously drilling a wellbore

ABSTRACT

A wellbore casing is formed simultaneously with the drilling out of the wellbore.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of the filing date of U.S.Provisional Patent Application Serial No. 60/124,042, filed on Mar. 11,1999, the disclosure of which is incorporated herein by reference.

This application is a division of U.S. patent application Ser. No.09/523,468, filed on Mar. 10, 2000, which was a continuation-in-part ofU.S. patent application Ser. No. 09/510,913, filed Feb. 23, 2000, nowabandoned, which claimed the benefit of the filing date of U.S.provisional patent application serial No. 60/121,702, filed on Feb. 25,1999, which was a continuation-in-part of U.S. patent application Ser.No. 09/502,350, filed on Feb. 10, 2000, now abandoned, which claimed thebenefit of the filing date of U.S. provisional patent application serialNo. 60/119,611, filed on Feb. 11, 1999, which was a continuation-in-partof U.S. patent application Ser. No. 09/454,139, filed on Dec. 3, 1999,which claimed the benefit of the filing date of U.S. provisional patentapplication serial No. 60/111,293, filed on Dec. 7, 1998.

This application is related to the following U.S. patent applications:(1) utility patent application Ser. No. 09/940,338, attorney docketnumber 25791.9.02, filed on Nov. 16, 1999, which claimed the benefit ofthe filing date of provisional patent application No. 60/108,558,attorney docket number 25791.9, filed on Nov. 16, 1998; (2) utilitypatent application Ser. No. 09/454,139, attorney docket number25791.3.02, filed on Dec. 3, 1999, which claimed the benefit of thefiling date of provisional patent application No. 60/111,293, attorneydocket number 25791.3, filed on Dec. 7, 1998; (3) utility patentapplication Ser. No. 09/502,350, attorney docket number 25791.8.02,filed on Feb. 10, 2000, which claimed the benefit of the filing date ofprovisional patent application No. 60/119,611, attorney docket number25791.8, filed on Feb. 11, 1999; (4) provisional patent application No.60/121,702, attorney docket number 25791.7, filed on Feb. 25, 1999; (5)provisional patent application No. 60/121,841, attorney docket number25791.12, filed on Feb. 26, 1999; (6) provisional patent application No.60/121,907, attorney docket number 25791.16, filed on Feb. 26, 1999; (7)provisional patent application No. 60/124,042, attorney docket number25791.11, filed on Mar. 11, 1999; (8) provisional patent application No.60/131,106, attorney docket number 25791.23, filed on Apr. 26, 1999; (9)provisional patent application No. 60/137,998, attorney docket number25791.17, filed on Jun. 7, 1999; (10) provisional patent application No.60/143,039, attorney docket number 25791.26, filed on Jul. 9, 1999; (11)provisional patent application No. 60/146,203, attorney docket number25791.25, filed on Jul. 29, 1999; (12) provisional patent applicationNo. 60/154,047, attorney docket number 25791.29, filed on Sep. 16, 1999;(13) provisional patent application No. 60/159,082, attorney docketnumber 25791.34, filed on Oct. 12, 1999; (14) provisional patentapplication No. 60/159,039, attorney docket number 25791.36, filed onOct. 12, 1999; (13) provisional patent application No. 60/159,033,attorney docket number 25791.37, filed on Oct. 12, 1999; and (15)provisional patent application No. 60/162,171, attorney docket number25791.27, filed on Nov. 1, 1999.

BACKGROUND OF THE INVENTION

This invention relates generally to wellbore casings, and in particularto wellbore casings that are formed using expandable tubing.

Conventionally, when a wellbore is created, a number of casings areinstalled in the borehole to prevent collapse of the borehole wall andto prevent undesired outflow of drilling fluid into the formation orinflow of fluid from the formation into the borehole. The borehole isdrilled in intervals whereby a casing which is to be installed in alower borehole interval is lowered through a previously installed casingof an upper borehole interval. As a consequence of this procedure thecasing of the lower interval is of smaller diameter than the casing ofthe upper interval. Thus, the casings are in a nested arrangement withcasing diameters decreasing in downward direction. Cement annuli areprovided between the outer surfaces of the casings and the borehole wallto seal the casings from the borehole wall. As a consequence of thisnested arrangement a relatively large borehole diameter is required atthe upper part of the wellbore. Such a large borehole diameter involvesincreased costs due to heavy casing handling equipment, large drill bitsand increased volumes of drilling fluid and drill cuttings. Moreover,increased drilling rig time is involved due to required cement pumping,cement hardening, required equipment changes due to large variations inhole diameters drilled in the course of the well, and the large volumeof cuttings drilled and removed.

Conventionally, at the surface end of the wellbore, a wellhead is formedthat typically includes a surface casing, a number of production and/ordrilling spools, valving, and a Christmas tree. Typically the wellheadfurther includes a concentric arrangement of casings including aproduction casing and one or more intermediate casings. The casings aretypically supported using load bearing slips positioned above theground. The conventional design and construction of wellheads isexpensive and complex.

Conventionally, a wellbore casing cannot be formed during the drillingof a wellbore. Typically, the wellbore is drilled and then a wellborecasing is formed in the newly drilled section of the wellbore. Thisdelays the completion of a well.

The present invention is directed to overcoming one or more of thelimitations of the existing procedures for forming wellbores andwellheads.

SUMMARY OF THE INVENTION

According to one aspect of the present invention, a method of forming awellbore casing is provided that includes installing a tubular liner anda mandrel in the borehole, injecting fluidic material into the borehole,and radially expanding the liner in the borehole by extruding the lineroff of the mandrel.

According to another aspect of the present invention, a method offorming a wellbore casing is provided that includes drilling out a newsection of the borehole adjacent to the already existing casing. Atubular liner and a mandrel are then placed into the new section of theborehole with the tubular liner overlapping an already existing casing.A hardenable fluidic sealing material is injected into an annular regionbetween the tubular liner and the new section of the borehole. Theannular region between the tubular liner and the new section of theborehole is then fluidicly isolated from an interior region of thetubular liner below the mandrel. A non hardenable fluidic material isthen injected into the interior region of the tubular liner below themandrel. The tubular liner is extruded off of the mandrel. The overlapbetween the tubular liner and the already existing casing is sealed. Thetubular liner is supported by overlap with the already existing casing.The mandrel is removed from the borehole. The integrity of the seal ofthe overlap between the tubular liner and the already existing casing istested. At least a portion of the second quantity of the hardenablefluidic sealing material is removed from the interior of the tubularliner. The remaining portions of the fluidic hardenable fluidic sealingmaterial are cured. At least a portion of cured fluidic hardenablesealing material within the tubular liner is removed.

According to another aspect of the present invention, an apparatus forexpanding a tubular member is provided that includes a support member, amandrel, a tubular member, and a shoe. The support member includes afirst fluid passage. The mandrel is coupled to the support member andincludes a second fluid passage. The tubular member is coupled to themandrel. The shoe is coupled to the tubular liner and includes a thirdfluid passage. The first, second and third fluid passages are operablycoupled.

According to another aspect of the present invention, an apparatus forexpanding a tubular member is provided that includes a support member,an expandable mandrel, a tubular member, a shoe, and at least onesealing member. The support member includes a first fluid passage, asecond fluid passage, and a flow control valve coupled to the first andsecond fluid passages. The expandable mandrel is coupled to the supportmember and includes a third fluid passage. The tubular member is coupledto the mandrel and includes one or more sealing elements. The shoe iscoupled to the tubular member and includes a fourth fluid passage. Theat least one sealing member is adapted to prevent the entry of foreignmaterial into an interior region of the tubular member.

According to another aspect of the present invention, a method ofjoining a second tubular member to a first tubular member, the firsttubular member having an inner diameter greater than an outer diameterof the second tubular member, is provided that includes positioning amandrel within an interior region of the second tubular member. Aportion of an interior region of the second tubular member ispressurized and the second tubular member is extruded off of the mandrelinto engagement with the first tubular member.

According to another aspect of the present invention, a tubular liner isprovided that includes an annular member having one or more sealingmembers at an end portion of the annular member, and one or morepressure relief passages at an end portion of the annular member.

According to another aspect of the present invention, a wellbore casingis provided that includes a tubular liner and an annular body of a curedfluidic sealing material. The tubular liner is formed by the process ofextruding the tubular liner off of a mandrel.

According to another aspect of the present invention, a tie-back linerfor lining an existing wellbore casing is provided that includes atubular liner and an annular body of cured fluidic sealing material. Thetubular liner is formed by the process of extruding the tubular lineroff of a mandrel. The annular body of a cured fluidic sealing materialis coupled to the tubular liner.

According to another aspect of the present invention, an apparatus forexpanding a tubular member is provided that includes a support member, amandrel, a tubular member and a shoe. The support member includes afirst fluid passage. The mandrel is coupled to the support member. Themandrel includes a second fluid passage operably coupled to the firstfluid passage, an interior portion, and an exterior portion. Theinterior portion of the mandrel is drillable. The tubular member iscoupled to the mandrel. The shoe is coupled to the tubular member. Theshoe includes a third fluid passage operably coupled to the second fluidpassage, an interior portion, and an exterior portion. The interiorportion of the shoe is drillable.

According to another aspect of the present invention, a wellhead isprovided that includes an outer casing and a plurality of concentricinner casings coupled to the outer casing. Each inner casing issupported by contact pressure between an outer surface of the innercasing and an inner surface of the outer casing.

According to another aspect of the present invention, a wellhead isprovided that include an outer casing at least partially positionedwithin a wellbore and a plurality of substantially concentric innercasings coupled to the interior surface of the outer casing. One or moreof the inner casings are coupled to the outer casing by expanding one ormore of the inner casings into contact with at least a portion of theinterior surface of the outer casing.

According to another aspect of the present invention, a method offorming a wellhead is provided that includes drilling a wellbore. Anouter casing is positioned at least partially within an upper portion ofthe wellbore. A first tubular member is positioned within the outercasing. At least a portion of the first tubular member is expanded intocontact with an interior surface of the outer casing. A second tubularmember is positioned within the outer casing and the first tubularmember. At least a portion of the second tubular member is expanded intocontact with an interior portion of the outer casing.

According to another aspect of the present invention, an apparatus isprovided that includes an outer tubular member, and a plurality ofsubstantially concentric and overlapping inner tubular members coupledto the outer tubular member. Each inner tubular member is supported bycontact pressure between an outer surface of the inner casing and aninner surface of the outer inner tubular member.

According to another aspect of the present invention, an apparatus isprovided that includes an outer tubular member, and a plurality ofsubstantially concentric inner tubular members coupled to the interiorsurface of the outer tubular member by the process of expanding one ormore of the inner tubular members into contact with at least a portionof the interior surface of the outer tubular member.

According to another aspect of the present invention, a wellbore casingis provided that includes a first tubular member, and a second tubularmember coupled to the first tubular member in an overlappingrelationship. The inner diameter of the first tubular member issubstantially equal to the inner diameter of the second tubular member.

According to another aspect of the present invention, a wellbore casingis provided that includes a tubular member including at least one thinwall section and a thick wall section, and a compressible annular membercoupled to each thin wall section.

According to another aspect of the present invention, a method ofcreating a casing in a borehole located in a subterranean formation isprovided that includes supporting a tubular liner and a mandrel in theborehole using a support member. A fluidic material is injected into theborehole. An interior region of the mandrel is pressurized. A portion ofthe mandrel is displaced relative to the support member. The tubularliner is expanded.

According to another aspect of the present invention, a wellbore casingis provided that includes a first tubular member having a first insidediameter, and a second tubular member having a second inside diametersubstantially equal to the first inside diameter coupled to the firsttubular member in an overlapping relationship. The first and secondtubular members are coupled by the process of deforming a portion of thesecond tubular member into contact with a portion of the first tubularmember

According to another aspect of the present invention, an apparatus forexpanding a tubular member is provided that includes a support memberincluding a fluid passage, a mandrel movably coupled to the supportmember including an expansion cone, at least one pressure chamberdefined by and positioned between the support member and mandrelfluidicly coupled to the first fluid passage, and one or more releasablesupports coupled to the support member adapted to support the tubularmember.

According to another aspect of the present invention, an apparatus isprovided that includes one or more solid tubular members, each solidtubular member including one or more external seals, one or more slottedtubular members coupled to the solid tubular members, and a shoe coupledto one of the slotted tubular members.

According to another aspect of the present invention, a method ofjoining a second tubular member to a first tubular member, the firsttubular member having an inner diameter greater than an outer diameterof the second tubular member is provided that includes positioning amandrel within an interior region of the second tubular member. Aportion of the interior region of the mandrel is pressurized. Themandrel is displaced relative to the second tubular member. At least aportion of the second tubular member is extruded off of the mandrel intoengagement with the first tubular member.

According to another aspect of the present invention, an apparatus isprovided that includes one or more primary solid tubulars, each primarysolid tubular including one or more external annular seals, n slottedtubulars coupled to the primary solid tubulars, n−1 intermediate solidtubulars coupled to and interleaved among the slotted tubulars, eachintermediate solid tubular including one or more external annular seals,and a shoe coupled to one of the slotted tubulars.

According to another aspect of the present invention, a method ofisolating a first subterranean zone from a second subterranean zone in awellbore is provided that includes positioning one or more primary solidtubulars within the wellbore, the primary solid tubulars traversing thefirst subterranean zone. One or more slotted tubulars are alsopositioned within the wellbore, the slotted tubulars traversing thesecond subterranean zone. The slotted tubulars and the solid tubularsare fluidicly coupled. The passage of fluids from the first subterraneanzone to the second subterranean zone within the wellbore external to thesolid and slotted tubulars is prevented.

According to another aspect of the present invention, a method ofextracting materials from a producing subterranean zone in a wellbore,at least a portion of the wellbore including a casing, is provided thatincludes positioning one or more primary solid tubulars within thewellbore. The primary solid tubulars with the casing are fluidiclycoupled. One or more slotted tubulars are positioned within thewellbore, the slotted tubulars traversing the producing subterraneanzone. The slotted tubulars are fluidicly coupled with the solidtubulars. The producing subterranean zone is fluidicly isolated from atleast one other subterranean zone within the wellbore. At least one ofthe slotted tubulars is fluidicly isolated from the producingsubterranean zone.

According to another aspect of the present invention, a method ofcreating a casing in a borehole while also drilling the borehole is alsoprovided that includes installing a tubular liner, a mandrel, and adrilling assembly in the borehole. A fluidic material is injected withinthe tubular liner, mandrel and drilling assembly. At least a portion ofthe tubular liner is radially expanded while the borehole is drilledusing the drilling assembly. In a preferred embodiment, the injectingincludes injecting the fluidic material within an expandible chamber.

According to another aspect of the present invention, an apparatus isalso provided that includes a support member, the support memberincluding a first fluid passage; a mandrel coupled to the supportmember, the mandrel including: a second fluid passage; a tubular membercoupled to the mandrel; and a shoe coupled to the tubular liner, theshoe including a third fluid passage; and a drilling assembly coupled tothe shoe; wherein the first, second and third fluid passages and thedrilling assembly are operably coupled.

According to another aspect of the present invention, a method offorming an underground pipeline within an underground tunnel includingat least a first tubular member and a second tubular member, the firsttubular member having an inner diameter greater than an outer diameterof the second tubular member, is also provided that includes positioningthe first tubular member within the tunnel; positioning the secondtubular member within the tunnel in an overlapping relationship with thefirst tubular member; positioning a mandrel and a drilling assemblywithin an interior region of the second tubular member; injecting afluidic material within the mandrel, drilling assembly and the secondtubular member; extruding at least a portion of the second tubularmember off of the mandrel into engagement with the first tubular member;and drilling the tunnel.

According to another aspect of the present invention, an apparatus isalso provided that includes a wellbore, the wellbore formed by theprocess of drilling the wellbore; and a tubular liner positioned withinthe wellbore, the tubular liner formed by the process of extruding thetubular liner off of a mandrel while drilling the wellbore. In apreferred embodiment, the tubular liner is formed by the process of:placing the tubular liner and mandrel within the wellbore; andpressurizing an interior portion of the tubular liner.

According to another aspect of the present invention, a method offorming a wellbore casing in a wellbore is also provided that includesdrilling out the wellbore while forming the wellbore casing.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a fragmentary cross-sectional view illustrating the drillingof a new section of a well borehole.

FIG. 2 is a fragmentary cross-sectional view illustrating the placementof an embodiment of an apparatus for creating a casing within the newsection of the well borehole.

FIG. 3 is a fragmentary cross-sectional view illustrating the injectionof a first quantity of a fluidic material into the new section of thewell borehole.

FIG. 3a is another fragmentary cross-sectional view illustrating theinjection of a first quantity of a hardenable fluidic sealing materialinto the new section of the well borehole.

FIG. 4 is a fragmentary cross-sectional view illustrating the injectionof a second quantity of a fluidic material into the new section of thewell borehole.

FIG. 5 is a fragmentary cross-sectional view illustrating the drillingout of a portion of the cured hardenable fluidic sealing material fromthe new section of the well borehole.

FIG. 6 is a cross-sectional view of an embodiment of the overlappingjoint between adjacent tubular members.

FIG. 7 is a fragmentary cross-sectional view of a preferred embodimentof the apparatus for creating a casing within a well borehole.

FIG. 8 is a fragmentary cross-sectional illustration of the placement ofan expanded tubular member within another tubular member.

FIG. 9 is a cross-sectional illustration of a preferred embodiment of anapparatus for forming a casing including a drillable mandrel and shoe.

FIG. 9a is another cross-sectional illustration of the apparatus of FIG.9.

FIG. 9b is another cross-sectional illustration of the apparatus of FIG.9.

FIG. 9c is another cross-sectional illustration of the apparatus of FIG.9.

FIG. 10a is a cross-sectional illustration of a wellbore including apair of adjacent overlapping casings.

FIG. 10b is a cross-sectional illustration of an apparatus and methodfor creating a tie-back liner using an expandible tubular member.

FIG. 10c is a cross-sectional illustration of the pumping of a fluidicsealing material into the annular region between the tubular member andthe existing casing.

FIG. 10d is a cross-sectional illustration of the pressurizing of theinterior of the tubular member below the mandrel.

FIG. 10e is a cross-sectional illustration of the extrusion of thetubular member off of the mandrel.

FIG. 10f is a cross-sectional illustration of the tie-back liner beforedrilling out the shoe and packer.

FIG. 10g is a cross-sectional illustration of the completed tie-backliner created using an expandible tubular member.

FIG. 11a is a fragmentary cross-sectional view illustrating the drillingof a new section of a well borehole.

FIG. 11b is a fragmentary cross-sectional view illustrating theplacement of an embodiment of an apparatus for hanging a tubular linerwithin the new section of the well borehole.

FIG. 11c is a fragmentary cross-sectional view illustrating theinjection of a first quantity of a hardenable fluidic sealing materialinto the new section of the well borehole.

FIG. 11d is a fragmentary cross-sectional view illustrating theintroduction of a wiper dart into the new section of the well borehole.

FIG. 11e is a fragmentary cross-sectional view illustrating theinjection of a second quantity of a hardenable fluidic sealing materialinto the new section of the well borehole.

FIG. 11f is a fragmentary cross-sectional view illustrating thecompletion of the tubular liner.

FIG. 12 is a cross-sectional illustration of a preferred embodiment of awellhead system utilizing expandable tubular members.

FIG. 13 is a partial cross-sectional illustration of a preferredembodiment of the wellhead system of FIG. 12.

FIG. 14a is an illustration of the formation of an embodiment of amono-diameter wellbore casing.

FIG. 14b is another illustration of the formation of the mono-diameterwellbore casing.

FIG. 14c is another illustration of the formation of the mono-diameterwellbore casing.

FIG. 14d is another illustration of the formation of the mono-diameterwellbore casing.

FIG. 14e is another illustration of the formation of the mono-diameterwellbore casing.

FIG. 14f is another illustration of the formation of the mono-diameterwellbore casing.

FIG. 15 is an illustration of an embodiment of an apparatus forexpanding a tubular member.

FIG. 15a is another illustration of the apparatus of FIG. 15.

FIG. 15b is another illustration of the apparatus of FIG. 15.

FIG. 16 is an illustration of an embodiment of an apparatus for forminga mono-diameter wellbore casing.

FIG. 17 is an illustration of an embodiment of an apparatus forexpanding a tubular member.

FIG. 17a is another illustration of the apparatus of FIG. 16.

FIG. 17b is another illustration of the apparatus of FIG. 16.

FIG. 18 is an illustration of an embodiment of an apparatus for forminga mono-diameter wellbore casing.

FIG. 19 is an illustration of another embodiment of an apparatus forexpanding a tubular member.

FIG. 19a is another illustration of the apparatus of FIG. 17.

FIG. 19b is another illustration of the apparatus of FIG. 17.

FIG. 20 is an illustration of an embodiment of an apparatus for forminga mono-diameter wellbore casing.

FIG. 21 is an illustration of the isolation of subterranean zones usingexpandable tubulars.

FIG. 22a is a fragmentary cross-sectional illustration of an embodimentof an apparatus for forming a wellbore casing while drilling a wellbore.

FIG. 22b is another fragmentary cross-sectional illustration of theapparatus of FIG. 22a.

FIG. 22c is another fragmentary cross-sectional illustration of theapparatus of FIG. 22a.

FIG. 22d is another fragmentary cross-sectional illustration of theapparatus of FIG. 22a.

DETAILED DESCRIPTION OF THE ILLUSTRATIVE EMBODIMENTS

An apparatus and method for forming a wellbore casing within asubterranean formation is provided. The apparatus and method permits awellbore casing to be formed in a subterranean formation by placing atubular member and a mandrel in a new section of a wellbore, and thenextruding the tubular member off of the mandrel by pressurizing aninterior portion of the tubular member. The apparatus and method furtherpermits adjacent tubular members in the wellbore to be joined using anoverlapping joint that prevents fluid and or gas passage. The apparatusand method further permits a new tubular member to be supported by anexisting tubular member by expanding the new tubular member intoengagement with the existing tubular member. The apparatus and methodfurther minimizes the reduction in the hole size of the wellbore casingnecessitated by the addition of new sections of wellbore casing.

An apparatus and method for forming a tie-back liner using an expandabletubular member is also provided. The apparatus and method permits atie-back liner to be created by extruding a tubular member off of amandrel by pressurizing and interior portion of the tubular member. Inthis manner, a tie-back liner is produced. The apparatus and methodfurther permits adjacent tubular members in the wellbore to be joinedusing an overlapping joint that prevents fluid and/or gas passage. Theapparatus and method further permits a new tubular member to besupported by an existing tubular member by expanding the new tubularmember into engagement with the existing tubular member.

An apparatus and method for expanding a tubular member is also providedthat includes an expandable tubular member, mandrel and a shoe. In apreferred embodiment, the interior portions of the apparatus is composedof materials that permit the interior portions to be removed using aconventional drilling apparatus. In this manner, in the event of amalfunction in a downhole region, the apparatus may be easily removed.

An apparatus and method for hanging an expandable tubular liner in awellbore is also provided. The apparatus and method permit a tubularliner to be attached to an existing section of casing. The apparatus andmethod further have application to the joining of tubular members ingeneral.

An apparatus and method for forming a wellhead system is also provided.The apparatus and method permit a wellhead to be formed including anumber of expandable tubular members positioned in a concentricarrangement. The wellhead preferably includes an outer casing thatsupports a plurality of concentric casings using contact pressurebetween the inner casings and the outer casing. The resulting wellheadsystem eliminates many of the spools conventionally required, reducesthe height of the Christmas tree facilitating servicing, lowers the loadbearing areas of the wellhead resulting in a more stable system, andeliminates costly and expensive hanger systems.

An apparatus and method for forming a mono-diameter well casing is alsoprovided. The apparatus and method permit the creation of a well casingin a wellbore having a substantially constant internal diameter. In thismanner, the operation of an oil or gas well is greatly simplified.

An apparatus and method for expanding tubular members is also provided.The apparatus and method utilize a piston-cylinder configuration inwhich a pressurized chamber is used to drive a mandrel to radiallyexpand tubular members. In this manner, higher operating pressures canbe utilized. Throughout the radial expansion process, the tubular memberis never placed in direct contact with the operating pressures. In thismanner, damage to the tubular member is prevented while also permittingcontrolled radial expansion of the tubular member in a wellbore.

An apparatus and method for forming a mono-diameter wellbore casing isalso provided. The apparatus and method utilize a piston-cylinderconfiguration in which a pressurized chamber is used to drive a mandrelto radially expand tubular members. In this manner, higher operatingpressures can be utilized. Throughput the radial expansion process, thetubular member is never placed in direct contact with the operatingpressures. In this manner, damage to the tubular member is preventedwhile also permitting controlled radial expansion of the tubular memberin a wellbore.

An apparatus and method for isolating one or more subterranean zonesfrom one or more other subterranean zones is also provided. Theapparatus and method permits a producing zone to be isolated from anonproducing zone using a combination of solid and slotted tubulars. Inthe production mode, the teachings of the present disclosure may be usedin combination with conventional, well known, production completionequipment and methods using a series of packers, solid tubing,perforated tubing, and sliding sleeves, which will be inserted into thedisclosed apparatus to permit the commingling and/or isolation of thesubterranean zones from each other.

An apparatus and method for forming a wellbore casing while the wellboreis drilled is also provided. In this manner, a wellbore casing can beformed simultaneous with the drilling out of a new section of thewellbore. In a preferred embodiment, the apparatus and method is used incombination with one or more of the apparatus and methods disclosed inthe present disclosure for forming wellbore casings using expandabletubulars. Alternatively, the method and apparatus can be used to createa pipeline or tunnel in a time efficient manner.

Referring initially to FIGS. 1-5, an embodiment of an apparatus andmethod for forming a wellbore casing within a subterranean formationwill now be described. As illustrated in FIG. 1, a wellbore 100 ispositioned in a subterranean formation 105. The wellbore 100 includes anexisting cased section 110 having a tubular casing 115 and an annularouter layer of cement 120.

In order to extend the wellbore 100 into the subterranean formation 105,a drill string 125 is used in a well known manner to drill out materialfrom the subterranean formation 105 to form a new section 130.

As illustrated in FIG. 2, an apparatus 200 for forming a wellbore casingin a subterranean formation is then positioned in the new section 130 ofthe wellbore 100. The apparatus 200 preferably includes an expandablemandrel or pig 205, a tubular member 210, a shoe 215, a lower cup seal220, an upper cup seal 225, a fluid passage 230, a fluid passage 235, afluid passage 240, seals 245, and a support member 250.

The expandable mandrel 205 is coupled to and supported by the supportmember 250. The expandable mandrel 205 is preferably adapted tocontrollably expand in a radial direction. The expandable mandrel 205may comprise any number of conventional commercially availableexpandable mandrels modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the expandable mandrel205 comprises a hydraulic expansion tool as disclosed in U.S. Pat. No.5,348,095, the contents of which are incorporated herein by reference,modified in accordance with the teachings of the present disclosure.

The tubular member 210 is supported by the expandable mandrel 205. Thetubular member 210 is expanded in the radial direction and extruded offof the expandable mandrel 205. The tubular member 210 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, Oilfield Country Tubular Goods (OCTG), 13 chromiumsteel tubing/casing, or plastic tubing/casing. In a preferredembodiment, the tubular member 210 is fabricated from OCTG in order tomaximize strength after expansion. The inner and outer diameters of thetubular member 210 may range, for example, from approximately 0.75 to 47inches and 1.05 to 48 inches, respectively. In a preferred embodiment,the inner and outer diameters of the tubular member 210 range from about3 to 15.5 inches and 3.5 to 16 inches, respectively in order tooptimally provide minimal telescoping effect in the most commonlydrilled wellbore sizes. The tubular member 210 preferably comprises asolid member.

In a preferred embodiment, the end portion 260 of the tubular member 210is slotted, perforated, or otherwise modified to catch or slow down themandrel 205 when it completes the extrusion of tubular member 210. In apreferred embodiment, the length of the tubular member 210 is limited tominimize the possibility of buckling. For typical tubular member 210materials, the length of the tubular member 210 is preferably limited tobetween about 40 to 20,000 feet in length.

The shoe 215 is coupled to the expandable mandrel 205 and the tubularmember 210. The shoe 215 includes fluid passage 240. The shoe 215 maycomprise any number of conventional commercially available shoes suchas, for example, Super Seal II float shoe, Super Seal II Down-Jet floatshoe or a guide shoe with a sealing sleeve for a latch down plugmodified in accordance with the teachings of the present disclosure. Ina preferred embodiment, the shoe 215 comprises an aluminum down-jetguide shoe with a sealing sleeve for a latch-down plug available fromHalliburton Energy Services in Dallas, Tex. modified in accordance withthe teachings of the present disclosure, in order to optimally guide thetubular member 210 in the wellbore, optimally provide an adequate sealbetween the interior and exterior diameters of the overlapping jointbetween the tubular members, and to optimally allow the complete drillout of the shoe and plug after the completion of the cementing andexpansion operations.

In a preferred embodiment, the shoe 215 includes one or more through andside outlet ports in fluidic communication with the fluid passage 240.In this manner, the shoe 215 optimally injects hardenable fluidicsealing material into the region outside the shoe 215 and tubular member210. In a preferred embodiment, the shoe 215 includes the fluid passage240 having an inlet geometry that can receive a dart and/or a ballsealing member. In this manner, the fluid passage 240 can be optimallysealed off by introducing a plug, dart and/or ball sealing elements intothe fluid passage 230.

The lower cup seal 220 is coupled to and supported by the support member250. The lower cup seal 220 prevents foreign materials from entering theinterior region of the tubular member 210 adjacent to the expandablemandrel 205. The lower cup seal 220 may comprise any number ofconventional commercially available cup seals such as, for example, TPcups, or Selective Injection Packer (SIP) cups modified in accordancewith the teachings of the present disclosure. In a preferred embodiment,the lower cup seal 220 comprises a SIP cup seal, available fromHalliburton Energy Services in Dallas, Tex. in order to optimally blockforeign material and contain a body of lubricant.

The upper cup seal 225 is coupled to and supported by the support member250. The upper cup seal 225 prevents foreign materials from entering theinterior region of the tubular member 210. The upper cup seal 225 maycomprise any number of conventional commercially available cup sealssuch as, for example, TP cups or SIP cups modified in accordance withthe teachings of the present disclosure. In a preferred embodiment, theupper cup seal 225 comprises a SIP cup, available from HalliburtonEnergy Services in Dallas, Tex. in order to optimally block the entry offoreign materials and contain a body of lubricant.

The fluid passage 230 permits fluidic materials to be transported to andfrom the interior region of the tubular member 210 below the expandablemandrel 205. The fluid passage 230 is coupled to and positioned withinthe support member 250 and the expandable mandrel 205. The fluid passage230 preferably extends from a position adjacent to the surface to thebottom of the expandable mandrel 205. The fluid passage 230 ispreferably positioned along a centerline of the apparatus 200.

The fluid passage 230 is preferably selected, in the casing running modeof operation, to transport materials such as drilling mud or formationfluids at flow rates and pressures ranging from about 0 to 3,000gallons/minute and 0 to 9,000 psi in order to minimize drag on thetubular member being run and to minimize surge pressures exerted on thewellbore which could cause a loss of wellbore fluids and lead to holecollapse.

The fluid passage 235 permits fluidic materials to be released from thefluid passage 230. In this manner, during placement of the apparatus 200within the new section 130 of the wellbore 100, fluidic materials 255forced up the fluid passage 230 can be released into the wellbore 100above the tubular member 210 thereby minimizing surge pressures on thewellbore section 130. The fluid passage 235 is coupled to and positionedwithin the support member 250. The fluid passage is further fluidiclycoupled to the fluid passage 230.

The fluid passage 235 preferably includes a control valve forcontrollably opening and closing the fluid passage 235. In a preferredembodiment, the control valve is pressure activated in order tocontrollably minimize surge pressures. The fluid passage 235 ispreferably positioned substantially orthogonal to the centerline of theapparatus 200.

The fluid passage 235 is preferably selected to convey fluidic materialsat flow rates and pressures ranging from about 0 to 3,000 gallons/minuteand 0 to 9,000 psi in order to reduce the drag on the apparatus 200during insertion into the new section 130 of the wellbore 100 and tominimize surge pressures on the new wellbore section 130.

The fluid passage 240 permits fluidic materials to be transported to andfrom the region exterior to the tubular member 210 and shoe 215. Thefluid passage 240 is coupled to and positioned within the shoe 215 influidic communication with the interior region of the tubular member 210below the expandable mandrel 205. The fluid passage 240 preferably has across-sectional shape that permits a plug, or other similar device, tobe placed in fluid passage 240 to thereby block further passage offluidic materials. In this manner, the interior region of the tubularmember 210 below the expandable mandrel 205 can be fluidicly isolatedfrom the region exterior to the tubular member 210. This permits theinterior region of the tubular member 210 below the expandable mandrel205 to be pressurized. The fluid passage 240 is preferably positionedsubstantially along the centerline of the apparatus 200.

The fluid passage 240 is preferably selected to convey materials such ascement, drilling mud or epoxies at flow rates and pressures ranging fromabout 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimallyfill the annular region between the tubular member 210 and the newsection 130 of the wellbore 100 with fluidic materials. In a preferredembodiment, the fluid passage 240 includes an inlet geometry that canreceive a dart and/or a ball sealing member. In this manner, the fluidpassage 240 can be sealed off by introducing a plug, dart and/or ballsealing elements into the fluid passage 230.

The seals 245 are coupled to and supported by an end portion 260 of thetubular member 210. The seals 245 are further positioned on an outersurface 265 of the end portion 260 of the tubular member 210. The seals245 permit the overlapping joint between the end portion 270 of thecasing 115 and the portion 260 of the tubular member 210 to be fluidiclysealed. The seals 245 may comprise any number of conventionalcommercially available seals such as, for example, lead, rubber, Teflon,or epoxy seals modified in accordance with the teachings of the presentdisclosure. In a preferred embodiment, the seals 245 are molded fromStratalock epoxy available from Halliburton Energy Services in Dallas,Tex. in order to optimally provide a load bearing interference fitbetween the end 260 of the tubular member 210 and the end 270 of theexisting casing 115.

In a preferred embodiment, the seals 245 are selected to optimallyprovide a sufficient frictional force to support the expanded tubularmember 210 from the existing casing 115. In a preferred embodiment, thefrictional force optimally provided by the seals 245 ranges from about1,000 to 1,000,000 lbf in order to optimally support the expandedtubular member 210.

The support member 250 is coupled to the expandable mandrel 205, tubularmember 210, shoe 215, and seals 220 and 225. The support member 250preferably comprises an annular member having sufficient strength tocarry the apparatus 200 into the new section 130 of the wellbore 100. Ina preferred embodiment, the support member 250 further includes one ormore conventional centralizers (not illustrated) to help stabilize theapparatus 200. In a preferred embodiment, the support member 250comprises coiled tubing.

In a preferred embodiment, a quantity of lubricant 275 is provided inthe annular region above the expandable mandrel 205 within the interiorof the tubular member 210. In this manner, the extrusion of the tubularmember 210 off of the expandable mandrel 205 is facilitated. Thelubricant 275 may comprise any number of conventional commerciallyavailable lubricants such as, for example, Lubriplate, chlorine basedlubricants, oil based lubricants or Climax 1500 Antisieze (3100). In apreferred embodiment, the lubricant 275 comprises Climax 1500 Antisieze(3100) available from Climax Lubricants and Equipment Co. in Houston,Tex. in order to optimally provide optimum lubrication to faciliate theexpansion process.

In a preferred embodiment, the support member 250 is thoroughly cleanedprior to assembly to the remaining portions of the apparatus 200. Inthis manner, the introduction of foreign material into the apparatus 200is minimized. This minimizes the possibility of foreign materialclogging the various flow passages and valves of the apparatus 200.

In a preferred embodiment, before or after positioning the apparatus 200within the new section 130 of the wellbore 100, a couple of wellborevolumes are circulated in order to ensure that no foreign materials arelocated within the wellbore 100 that might clog up the various flowpassages and valves of the apparatus 200 and to ensure that no foreignmaterial interferes with the expansion process.

As illustrated in FIG. 3, the fluid passage 235 is then closed and ahardenable fluidic sealing material 305 is then pumped from a surfacelocation into the fluid passage 230. The material 305 then passes fromthe fluid passage 230 into the interior region 310 of the tubular member210 below the expandable mandrel 205. The material 305 then passes fromthe interior region 310 into the fluid passage 240. The material 305then exits the apparatus 200 and fills the annular region 315 betweenthe exterior of the tubular member 210 and the interior wall of the newsection 130 of the wellbore 100. Continued pumping of the material 305causes the material 305 to fill up at least a portion of the annularregion 315.

The material 305 is preferably pumped into the annular region 315 atpressures and flow rates ranging, for example, from about 0 to 5000 psiand 0 to 1,500 gallons/min, respectively. The optimum flow rate andoperating pressures vary as a function of the casing and wellbore sizes,wellbore section length, available pumping equipment, and fluidproperties of the fluidic material being pumped. The optimum flow rateand operating pressure are preferably determined using conventionalempirical methods.

The hardenable fluidic sealing material 305 may comprise any number ofconventional commercially available hardenable fluidic sealing materialssuch as, for example, slag mix, cement or epoxy. In a preferredembodiment, the hardenable fluidic sealing material 305 comprises ablended cement prepared specifically for the particular well sectionbeing drilled from Halliburton Energy Services in Dallas, Tex. in orderto provide optimal support for tubular member 210 while also maintainingoptimum flow characteristics so as to minimize difficulties during thedisplacement of cement in the annular region 315. The optimum blend ofthe blended cement is preferably determined using conventional empiricalmethods.

The annular region 315 preferably is filled with the material 305 insufficient quantities to ensure that, upon radial expansion of thetubular member 210, the annular region 315 of the new section 130 of thewellbore 100 will be filled with material 305.

In a particularly preferred embodiment, as illustrated in FIG. 3a, thewall thickness and/or the outer diameter of the tubular member 210 isreduced in the region adjacent to the mandrel 205 in order optimallypermit placement of the apparatus 200 in positions in the wellbore withtight clearances. Furthermore, in this manner, the initiation of theradial expansion of the tubular member 210 during the extrusion processis optimally facilitated.

As illustrated in FIG. 4, once the annular region 315 has beenadequately filled with material 305, a plug 405, or other similardevice, is introduced into the fluid passage 240 thereby fluidiclyisolating the interior region 310 from the annular region 315. In apreferred embodiment, a non-hardenable fluidic material 306 is thenpumped into the interior region 310 causing the interior region topressurize. In this manner, the interior of the expanded tubular member210 will not contain significant amounts of cured material 305. Thisreduces and simplifies the cost of the entire process. Alternatively,the material 305 may be used during this phase of the process.

Once the interior region 310 becomes sufficiently pressurized, thetubular member 210 is extruded off of the expandable mandrel 205. Duringthe extrusion process, the expandable mandrel 205 may be raised out ofthe expanded portion of the tubular member 210. In a preferredembodiment, during the extrusion process, the mandrel 205 is raised atapproximately the same rate as the tubular member 210 is expanded inorder to keep the tubular member 210 stationary relative to the newwellbore section 130. In an alternative preferred embodiment, theextrusion process is commenced with the tubular member 210 positionedabove the bottom of the new wellbore section 130, keeping the mandrel205 stationary, and allowing the tubular member 210 to extrude off ofthe mandrel 205 and fall down the new wellbore section 130 under theforce of gravity.

The plug 405 is preferably placed into the fluid passage 240 byintroducing the plug 405 into the fluid passage 230 at a surfacelocation in a conventional manner. The plug 405 preferably acts tofluidicly isolate the hardenable fluidic sealing material 305 from thenon hardenable fluidic material 306.

The plug 405 may comprise any number of conventional commerciallyavailable devices from plugging a fluid passage such as, for example,Multiple Stage Cementer (MSC) latch-down plug, Omega latch-down plug orthree-wiper latch-down plug modified in accordance with the teachings ofthe present disclosure. In a preferred embodiment, the plug 405comprises a MSC latch-down plug available from Halliburton EnergyServices in Dallas, Tex.

After placement of the plug 405 in the fluid passage 240, a nonhardenable fluidic material 306 is preferably pumped into the interiorregion 310 at pressures and flow rates ranging, for example, fromapproximately 400 to 10,000 psi and 30 to 4,000 gallons/min. In thismanner, the amount of hardenable fluidic sealing material within theinterior 310 of the tubular member 210 is minimized. In a preferredembodiment, after placement of the plug 405 in the fluid passage 240,the non hardenable material 306 is preferably pumped into the interiorregion 310 at pressures and flow rates ranging from approximately 500 to9,000 psi and 40 to 3,000 gallons/min in order to maximize the extrusionspeed.

In a preferred embodiment, the apparatus 200 is adapted to minimizetensile, burst, and friction effects upon the tubular member 210 duringthe expansion process. These effects will depend upon the geometry ofthe expansion mandrel 205, the material composition of the tubularmember 210 and expansion mandrel 205, the inner diameter of the tubularmember 210, the wall thickness of the tubular member 210, the type oflubricant, and the yield strength of the tubular member 210. In general,the thicker the wall thickness, the smaller the inner diameter, and thegreater the yield strength of the tubular member 210, then the greaterthe operating pressures required to extrude the tubular member 210 offof the mandrel 205.

For typical tubular members 210, the extrusion of the tubular member 210off of the expandable mandrel will begin when the pressure of theinterior region 310 reaches, for example, approximately 500 to 9,000psi.

During the extrusion process, the expandable mandrel 205 may be raisedout of the expanded portion of the tubular member 210 at rates ranging,for example, from about 0 to 5 ft/sec. In a preferred embodiment, duringthe extrusion process, the expandable mandrel 205 is raised out of theexpanded portion of the tubular member 210 at rates ranging from about 0to 2 ft/sec in order to minimize the time required for the expansionprocess while also permitting easy control of the expansion process.

When the end portion 260 of the tubular member 210 is extruded off ofthe expandable mandrel 205, the outer surface 265 of the end portion 260of the tubular member 210 will preferably contact the interior surface410 of the end portion 270 of the casing 115 to form an fluid tightoverlapping joint. The contact pressure of the overlapping joint mayrange, for example, from approximately 50 to 20,000 psi. In a preferredembodiment, the contact pressure of the overlapping joint ranges fromapproximately 400 to 10,000 psi in order to provide optimum pressure toactivate the annular sealing members 245 and optimally provideresistance to axial motion to accommodate typical tensile andcompressive loads.

The overlapping joint between the section 410 of the existing casing 115and the section 265 of the expanded tubular member 210 preferablyprovides a gaseous and fluidic seal. In a particularly preferredembodiment, the sealing members 245 optimally provide a fluidic andgaseous seal in the overlapping joint.

In a preferred embodiment, the operating pressure and flow rate of thenon hardenable fluidic material 306 is controllably ramped down when theexpandable mandrel 205 reaches the end portion 260 of the tubular member210. In this manner, the sudden release of pressure caused by thecomplete extrusion of the tubular member 210 off of the expandablemandrel 205 can be minimized. In a preferred embodiment, the operatingpressure is reduced in a substantially linear fashion from 100% to about10% during the end of the extrusion process beginning when the mandrel205 is within about 5 feet from completion of the extrusion process.

Alternatively, or in combination, a shock absorber is provided in thesupport member 250 in order to absorb the shock caused by the suddenrelease of pressure. The shock absorber may comprise, for example, anyconventional commercially available shock absorber adapted for use inwellbore operations.

Alternatively, or in combination, a mandrel catching structure isprovided in the end portion 260 of the tubular member 210 in order tocatch or at least decelerate the mandrel 205.

Once the extrusion process is completed, the expandable mandrel 205 isremoved from the wellbore 100. In a preferred embodiment, either beforeor after the removal of the expandable mandrel 205, the integrity of thefluidic seal of the overlapping joint between the upper portion 260 ofthe tubular member 210 and the lower portion 270 of the casing 115 istested using conventional methods.

If the fluidic seal of the overlapping joint between the upper portion260 of the tubular member 210 and the lower portion 270 of the casing115 is satisfactory, then any uncured portion of the material 305 withinthe expanded tubular member 210 is then removed in a conventional mannersuch as, for example, circulating the uncured material out of theinterior of the expanded tubular member 210. The mandrel 205 is thenpulled out of the wellbore section 130 and a drill bit or mill is usedin combination with a conventional drilling assembly 505 to drill outany hardened material 305 within the tubular member 210. The material305 within the annular region 315 is then allowed to cure.

As illustrated in FIG. 5, preferably any remaining cured material 305within the interior of the expanded tubular member 210 is then removedin a conventional manner using a conventional drill string 505. Theresulting new section of casing 510 includes the expanded tubular member210 and an outer annular layer 515 of cured material 305. The bottomportion of the apparatus 200 comprising the shoe 215 and dart 405 maythen be removed by drilling out the shoe 215 and dart 405 usingconventional drilling methods.

In a preferred embodiment, as illustrated in FIG. 6, the upper portion260 of the tubular member 210 includes one or more sealing members 605and one or more pressure relief holes 610. In this manner, theoverlapping joint between the lower portion 270 of the casing 115 andthe upper portion 260 of the tubular member 210 is pressure-tight andthe pressure on the interior and exterior surfaces of the tubular member210 is equalized during the extrusion process.

In a preferred embodiment, the sealing members 605 are seated withinrecesses 615 formed in the outer surface 265 of the upper portion 260 ofthe tubular member 210. In an alternative preferred embodiment, thesealing members 605 are bonded or molded onto the outer surface 265 ofthe upper portion 260 of the tubular member 210. The pressure reliefholes 610 are preferably positioned in the last few feet of the tubularmember 210. The pressure relief holes reduce the operating pressuresrequired to expand the upper portion 260 of the tubular member 210. Thisreduction in required operating pressure in turn reduces the velocity ofthe mandrel 205 upon the completion of the extrusion process. Thisreduction in velocity in turn minimizes the mechanical shock to theentire apparatus 200 upon the completion of the extrusion process.

Referring now to FIG. 7, a particularly preferred embodiment of anapparatus 700 for forming a casing within a wellbore preferably includesan expandable mandrel or pig 705, an expandable mandrel or pig container710, a tubular member 715, a float shoe 720, a lower cup seal 725, anupper cup seal 730, a fluid passage 735, a fluid passage 740, a supportmember 745, a body of lubricant 750, an overshot connection 755, anothersupport member 760, and a stabilizer 765.

The expandable mandrel 705 is coupled to and supported by the supportmember 745. The expandable mandrel 705 is further coupled to theexpandable mandrel container 710. The expandable mandrel 705 ispreferably adapted to controllably expand in a radial direction. Theexpandable mandrel 705 may comprise any number of conventionalcommercially available expandable mandrels modified in accordance withthe teachings of the present disclosure. In a preferred embodiment, theexpandable mandrel 705 comprises a hydraulic expansion toolsubstantially as disclosed in U.S. Pat. No. 5,348,095, the contents ofwhich are incorporated herein by reference, modified in accordance withthe teachings of the present disclosure.

The expandable mandrel container 710 is coupled to and supported by thesupport member 745. The expandable mandrel container 710 is furthercoupled to the expandable mandrel 705. The expandable mandrel container710 may be constructed from any number of conventional commerciallyavailable materials such as, for example, Oilfield Country TubularGoods, stainless steel, titanium or high strength steels. In a preferredembodiment, the expandable mandrel container 710 is fabricated frommaterial having a greater strength than the material from which thetubular member 715 is fabricated. In this manner, the container 710 canbe fabricated from a tubular material having a thinner wall thicknessthan the tubular member 210. This permits the container 710 to passthrough tight clearances thereby facilitating its placement within thewellbore.

In a preferred embodiment, once the expansion process begins, and thethicker, lower strength material of the tubular member 715 is expanded,the outside diameter of the tubular member 715 is greater than theoutside diameter of the container 710.

The tubular member 715 is coupled to and supported by the expandablemandrel 705. The tubular member 715 is preferably expanded in the radialdirection and extruded off of the expandable mandrel 705 substantiallyas described above with reference to FIGS. 1-6. The tubular member 715may be fabricated from any number of materials such as, for example,Oilfield Country Tubular Goods (OCTG), automotive grade steel orplastics. In a preferred embodiment, the tubular member 715 isfabricated from OCTG.

In a preferred embodiment, the tubular member 715 has a substantiallyannular cross-section. In a particularly preferred embodiment, thetubular member 715 has a substantially circular annular cross-section.

The tubular member 715 preferably includes an upper section 805, anintermediate section 810, and a lower section 815. The upper section 805of the tubular member 715 preferably is defined by the region beginningin the vicinity of the mandrel container 710 and ending with the topsection 820 of the tubular member 715. The intermediate section 810 ofthe tubular member 715 is preferably defined by the region beginning inthe vicinity of the top of the mandrel container 710 and ending with theregion in the vicinity of the mandrel 705. The lower section of thetubular member 715 is preferably defined by the region beginning in thevicinity of the mandrel 705 and ending at the bottom 825 of the tubularmember 715.

In a preferred embodiment, the wall thickness of the upper section 805of the tubular member 715 is greater than the wall thicknesses of theintermediate and lower sections 810 and 815 of the tubular member 715 inorder to optimally faciliate the initiation of the extrusion process andoptimally permit the apparatus 700 to be positioned in locations in thewellbore having tight clearances.

The outer diameter and wall thickness of the upper section 805 of thetubular member 715 may range, for example, from about 1.05 to 48 inchesand ⅛ to 2 inches, respectively. In a preferred embodiment, the outerdiameter and wall thickness of the upper section 805 of the tubularmember 715 range from about 3.5 to 16 inches and ⅜ to 1.5 inches,respectively.

The outer diameter and wall thickness of the intermediate section 810 ofthe tubular member 715 may range, for example, from about 2.5 to 50inches and {fraction (1/16)} to 1.5 inches, respectively. In a preferredembodiment, the outer diameter and wall thickness of the intermediatesection 810 of the tubular member 715 range from about 3.5 to 19 inchesand ⅛ to 1.25 inches, respectively.

The outer diameter and wall thickness of the lower section 815 of thetubular member 715 may range, for example, from about 2.5 to 50 inchesand {fraction (1/16)} to 1.25 inches, respectively. In a preferredembodiment, the outer diameter and wall thickness of the lower section810 of the tubular member 715 range from about 3.5 to 19 inches and ⅛ to1.25 inches, respectively. In a particularly preferred embodiment, thewall thickness of the lower section 815 of the tubular member 715 isfurther increased to increase the strength of the shoe 720 whendrillable materials such as, for example, aluminum are used.

The tubular member 715 preferably comprises a solid tubular member. In apreferred embodiment, the end portion 820 of the tubular member 715 isslotted, perforated, or otherwise modified to catch or slow down themandrel 705 when it completes the extrusion of tubular member 715. In apreferred embodiment, the length of the tubular member 715 is limited tominimize the possibility of buckling. For typical tubular member 715materials, the length of the tubular member 715 is preferably limited tobetween about 40 to 20,000 feet in length.

The shoe 720 is coupled to the expandable mandrel 705 and the tubularmember 715. The shoe 720 includes the fluid passage 740. In a preferredembodiment, the shoe 720 further includes an inlet passage 830, and oneor more jet ports 835. In a particularly preferred embodiment, thecross-sectional shape of the inlet passage 830 is adapted to receive alatch-down dart, or other similar elements, for blocking the inletpassage 830. The interior of the shoe 720 preferably includes a body ofsolid material 840 for increasing the strength of the shoe 720. In aparticularly preferred embodiment, the body of solid material 840comprises aluminum.

The shoe 720 may comprise any number of conventional commerciallyavailable shoes such as, for example, Super Seal II Down-Jet float shoe,or guide shoe with a sealing sleeve for a latch down plug modified inaccordance with the teachings of the present disclosure. In a preferredembodiment, the shoe 720 comprises an aluminum down-jet guide shoe witha sealing sleeve for a latch-down plug available from Halliburton EnergyServices in Dallas, Tex., modified in accordance with the teachings ofthe present disclosure, in order to optimize guiding the tubular member715 in the wellbore, optimize the seal between the tubular member 715and an existing wellbore casing, and to optimally faciliate the removalof the shoe 720 by drilling it out after completion of the extrusionprocess.

The lower cup seal 725 is coupled to and supported by the support member745. The lower cup seal 725 prevents foreign materials from entering theinterior region of the tubular member 715 above the expandable mandrel705. The lower cup seal 725 may comprise any number of conventionalcommercially available cup seals such as, for example, TP cups orSelective Injection Packer (SIP) cups modified in accordance with theteachings of the present disclosure. In a preferred embodiment, thelower cup seal 725 comprises a SIP cup, available from HalliburtonEnergy Services in Dallas, Tex. in order to optimally provide a debrisbarrier and hold a body of lubricant.

The upper cup seal 730 is coupled to and supported by the support member760. The upper cup seal 730 prevents foreign materials from entering theinterior region of the tubular member 715. The upper cup seal 730 maycomprise any number of conventional commercially available cup sealssuch as, for example, TP cups or Selective Injection Packer (SIP) cupmodified in accordance with the teachings of the present disclosure. Ina preferred embodiment, the upper cup seal 730 comprises a SIP cupavailable from Halliburton Energy Services in Dallas, Tex. in order tooptimally provide a debris barrier and contain a body of lubricant.

The fluid passage 735 permits fluidic materials to be transported to andfrom the interior region of the tubular member 715 below the expandablemandrel 705. The fluid passage 735 is fluidicly coupled to the fluidpassage 740. The fluid passage 735 is preferably coupled to andpositioned within the support member 760, the support member 745, themandrel container 710, and the expandable mandrel 705. The fluid passage735 preferably extends from a position adjacent to the surface to thebottom of the expandable mandrel 705. The fluid passage 735 ispreferably positioned along a centerline of the apparatus 700. The fluidpassage 735 is preferably selected to transport materials such ascement, drilling mud or epoxies at flow rates and pressures ranging fromabout 40 to 3,000 gallons/minute and 500 to 9,000 psi in order tooptimally provide sufficient operating pressures to extrude the tubularmember 715 off of the expandable mandrel 705.

As described above with reference to FIGS. 1-6, during placement of theapparatus 700 within a new section of a wellbore, fluidic materialsforced up the fluid passage 735 can be released into the wellbore abovethe tubular member 715. In a preferred embodiment, the apparatus 700further includes a pressure release passage that is coupled to andpositioned within the support member 260. The pressure release passageis further fluidicly coupled to the fluid passage 735. The pressurerelease passage preferably includes a control valve for controllablyopening and closing the fluid passage. In a preferred embodiment, thecontrol valve is pressure activated in order to controllably minimizesurge pressures. The pressure release passage is preferably positionedsubstantially orthogonal to the centerline of the apparatus 700. Thepressure release passage is preferably selected to convey materials suchas cement, drilling mud or epoxies at flow rates and pressures rangingfrom about 0 to 500 gallons/minute and 0 to 1,000 psi in order to reducethe drag on the apparatus 700 during insertion into a new section of awellbore and to minimize surge pressures on the new wellbore section.

The fluid passage 740 permits fluidic materials to be transported to andfrom the region exterior to the tubular member 715. The fluid passage740 is preferably coupled to and positioned within the shoe 720 influidic communication with the interior region of the tubular member 715below the expandable mandrel 705. The fluid passage 740 preferably has across-sectional shape that permits a plug, or other similar device, tobe placed in the inlet 830 of the fluid passage 740 to thereby blockfurther passage of fluidic materials. In this manner, the interiorregion of the tubular member 715 below the expandable mandrel 705 can beoptimally fluidicly isolated from the region exterior to the tubularmember 715. This permits the interior region of the tubular member 715below the expandable mandrel 205 to be pressurized.

The fluid passage 740 is preferably positioned substantially along thecenterline of the apparatus 700. The fluid passage 740 is preferablyselected to convey materials such as cement, drilling mud or epoxies atflow rates and pressures ranging from about 0 to 3,000 gallons/minuteand 0 to 9,000 psi in order to optimally fill an annular region betweenthe tubular member 715 and a new section of a wellbore with fluidicmaterials. In a preferred embodiment, the fluid passage 740 includes aninlet passage 830 having a geometry that can receive a dart and/or aball sealing member. In this manner, the fluid passage 240 can be sealedoff by introducing a plug, dart and/or ball sealing elements into thefluid passage 230.

In a preferred embodiment, the apparatus 700 further includes one ormore seals 845 coupled to and supported by the end portion 820 of thetubular member 715. The seals 845 are further positioned on an outersurface of the end portion 820 of the tubular member 715. The seals 845permit the overlapping joint between an end portion of preexistingcasing and the end portion 820 of the tubular member 715 to be fluidiclysealed. The seals 845 may comprise any number of conventionalcommercially available seals such as, for example, lead, rubber, Teflon,or epoxy seals modified in accordance with the teachings of the presentdisclosure. In a preferred embodiment, the seals 845 comprise sealsmolded from StrataLock epoxy available from Halliburton Energy Servicesin Dallas, Tex. in order to optimally provide a hydraulic seal and aload bearing interference fit in the overlapping joint between thetubular member 715 and an existing casing with optimal load bearingcapacity to support the tubular member 715.

In a preferred embodiment, the seals 845 are selected to provide asufficient frictional force to support the expanded tubular member 715from the existing casing. In a preferred embodiment, the frictionalforce provided by the seals 845 ranges from about 1,000 to 1,000,000 lbfin order to optimally support the expanded tubular member 715.

The support member 745 is preferably coupled to the expandable mandrel705 and the overshot connection 755. The support member 745 preferablycomprises an annular member having sufficient strength to carry theapparatus 700 into a new section of a wellbore. The support member 745may comprise any number of conventional commercially available supportmembers such as, for example, steel drill pipe, coiled tubing or otherhigh strength tubular modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the support member 745comprises conventional drill pipe available from various steel mills inthe United States.

In a preferred embodiment, a body of lubricant 750 is provided in theannular region above the expandable mandrel container 710 within theinterior of the tubular member 715. In this manner, the extrusion of thetubular member 715 off of the expandable mandrel 705 is facilitated. Thelubricant 705 may comprise any number of conventional commerciallyavailable lubricants such as, for example, Lubriplate, chlorine basedlubricants, oil based lubricants, or Climax 1500 Antisieze (3100). In apreferred embodiment, the lubricant 750 comprises Climax 1500 Antisieze(3100) available from Halliburton Energy Services in Houston, Tex. inorder to optimally provide lubrication to faciliate the extrusionprocess.

The overshot connection 755 is coupled to the support member 745 and thesupport member 760. The overshot connection 755 preferably permits thesupport member 745 to be removably coupled to the support member 760.The overshot connection 756 may comprise any number of conventionalcommercially available overshot connections such as, for example,Innerstring Sealing Adapter, Innerstring Flat-Face Sealing Adapter or EZDrill Setting Tool Stinger. In a preferred embodiment, the overshotconnection 755 comprises a Innerstring Adapter with an Upper Guideavailable from Halliburton Energy Services in Dallas, Tex.

The support member 760 is preferably coupled to the overshot connection755 and a surface support structure (not illustrated). The supportmember 760 preferably comprises an annular member having sufficientstrength to carry the apparatus 700 into a new section of a wellbore.The support member 760 may comprise any number of conventionalcommercially available support members such as, for example, steel drillpipe, coiled tubing or other high strength tubulars modified inaccordance with the teachings of the present disclosure. In a preferredembodiment, the support member 760 comprises a conventional drill pipeavailable from steel mills in the United States.

The stabilizer 765 is preferably coupled to the support member 760. Thestabilizer 765 also preferably stabilizes the components of theapparatus 700 within the tubular member 715. The stabilizer 765preferably comprises a spherical member having an outside diameter thatis about 80 to 99% of the interior diameter of the tubular member 715 inorder to optimally minimize buckling of the tubular member 715. Thestabilizer 765 may comprise any number of conventional commerciallyavailable stabilizers such as, for example, EZ Drill Star Guides, packershoes or drag blocks modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the stabilizer 765comprises a sealing adapter upper guide available from HalliburtonEnergy Services in Dallas, Tex.

In a preferred embodiment, the support members 745 and 760 arethoroughly cleaned prior to assembly to the remaining portions of theapparatus 700. In this manner, the introduction of foreign material intothe apparatus 700 is minimized. This minimizes the possibility offoreign material clogging the various flow passages and valves of theapparatus 700.

In a preferred embodiment, before or after positioning the apparatus 700within a new section of a wellbore, a couple of wellbore volumes arecirculated through the various flow passages of the apparatus 700 inorder to ensure that no foreign materials are located within thewellbore that might clog up the various flow passages and valves of theapparatus 700 and to ensure that no foreign material interferes with theexpansion mandrel 705 during the expansion process.

In a preferred embodiment, the apparatus 700 is operated substantiallyas described above with reference to FIGS. 1-7 to form a new section ofcasing within a wellbore.

As illustrated in FIG. 8, in an alternative preferred embodiment, themethod and apparatus described herein is used to repair an existingwellbore casing 805 by forming a tubular liner 810 inside of theexisting wellbore casing 805. In a preferred embodiment, an outerannular lining of cement is not provided in the repaired section. In thealternative preferred embodiment, any number of fluidic materials can beused to expand the tubular liner 810 into intimate contact with thedamaged section of the wellbore casing such as, for example, cement,epoxy, slag mix, or drilling mud. In the alternative preferredembodiment, sealing members 815 are preferably provided at both ends ofthe tubular member in order to optimally provide a fluidic seal. In analternative preferred embodiment, the tubular liner 810 is formed withina horizontally positioned pipeline section, such as those used totransport hydrocarbons or water, with the tubular liner 810 placed in anoverlapping relationship with the adjacent pipeline section. In thismanner, underground pipelines can be repaired without having to dig outand replace the damaged sections.

In another alternative preferred embodiment, the method and apparatusdescribed herein is used to directly line a wellbore with a tubularliner 810. In a preferred embodiment, an outer annular lining of cementis not provided between the tubular liner 810 and the wellbore. In thealternative preferred embodiment, any number of fluidic materials can beused to expand the tubular liner 810 into intimate contact with thewellbore such as, for example, cement, epoxy, slag mix, or drilling mud.

Referring now to FIGS. 9, 9 a, 9 b and 9 c, a preferred embodiment of anapparatus 900 for forming a wellbore casing includes an expandibletubular member 902, a support member 904, an expandible mandrel or pig906, and a shoe 908. In a preferred embodiment, the design andconstruction of the mandrel 906 and shoe 908 permits easy removal ofthose elements by drilling them out. In this manner, the assembly 900can be easily removed from a wellbore using a conventional drillingapparatus and corresponding drilling methods.

The expandible tubular member 902 preferably includes an upper portion910, an intermediate portion 912 and a lower portion 914. Duringoperation of the apparatus 900, the tubular member 902 is preferablyextruded off of the mandrel 906 by pressurizing an interior region 966of the tubular member 902. The tubular member 902 preferably has asubstantially annular cross-section.

In a particularly preferred embodiment, an expandable tubular member 915is coupled to the upper portion 910 of the expandable tubular member902. During operation of the apparatus 900, the tubular member 915 ispreferably extruded off of the mandrel 906 by pressurizing the interiorregion 966 of the tubular member 902. The tubular member 915 preferablyhas a substantially annular cross-section. In a preferred embodiment,the wall thickness of the tubular member 915 is greater than the wallthickness of the tubular member 902.

The tubular member 915 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfieldtubulars, low alloy steels, titanium or stainless steels. In a preferredembodiment, the tubular member 915 is fabricated from oilfield tubularsin order to optimally provide approximately the same mechanicalproperties as the tubular member 902. In a particularly preferredembodiment, the tubular member 915 has a plastic yield point rangingfrom about 400,000 to 135,000 psi in order to optimally provideapproximately the same yield properties as the tubular member 902. Thetubular member 915 may comprise a plurality of tubular members coupledend to end.

In a preferred embodiment, the upper end portion of the tubular member915 includes one or more sealing members for optimally providing afluidic and/or gaseous seal with an existing section of wellbore casing.

In a preferred embodiment, the combined length of the tubular members902 and 915 are limited to minimize the possibility of buckling. Fortypical tubular member materials, the combined length of the tubularmembers 902 and 915 are limited to between about 40 to 20,000 feet inlength.

The lower portion 914 of the tubular member 902 is preferably coupled tothe shoe 908 by a threaded connection 968. The intermediate portion 912of the tubular member 902 preferably is placed in intimate slidingcontact with the mandrel 906.

The tubular member 902 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfieldtubulars, low alloy steels, titanium or stainless steels. In a preferredembodiment, the tubular member 902 is fabricated from oilfield tubularsin order to optimally provide approximately the same mechanicalproperties as the tubular member 915. In a particularly preferredembodiment, the tubular member 902 has a plastic yield point rangingfrom about 400,000 to 135,000 psi in order to optimally provideapproximately the same yield properties as the tubular member 915.

The wall thickness of the upper, intermediate, and lower portions, 910,912 and 914 of the tubular member 902 may range, for example, from about{fraction (1/16)} to 1.5 inches. In a preferred embodiment, the wallthickness of the upper, intermediate, and lower portions, 910, 912 and914 of the tubular member 902 range from about ⅛ to 1.25 in order tooptimally provide wall thickness that are about the same as the tubularmember 915. In a preferred embodiment, the wall thickness of the lowerportion 914 is less than or equal to the wall thickness of the upperportion 910 in order to optimally provide a geometry that will fit intotight clearances downhole.

The outer diameter of the upper, intermediate, and lower portions, 910,912 and 914 of the tubular member 902 may range, for example, from about1.05 to 48 inches. In a preferred embodiment, the outer diameter of theupper, intermediate, and lower portions, 910, 912 and 914 of the tubularmember 902 range from about 3½ to 19 inches in order to optimallyprovide the ability to expand the most commonly used oilfield tubulars.

The length of the tubular member 902 is preferably limited to betweenabout 2 to 5 feet in order to optimally provide enough length to containthe mandrel 906 and a body of lubricant.

The tubular member 902 may comprise any number of conventionalcommercially available tubular members modified in accordance with theteachings of the present disclosure. In a preferred embodiment, thetubular member 902 comprises Oilfield Country Tubular Goods availablefrom various U.S. steel mills. The tubular member 915 may comprise anynumber of conventional commercially available tubular members modifiedin accordance with the teachings of the present disclosure. In apreferred embodiment, the tubular member 915 comprises Oilfield CountryTubular Goods available from various U.S. steel mills.

The various elements of the tubular member 902 may be coupled using anynumber of conventional process such as, for example, threadedconnections, welding or machined from one piece. In a preferredembodiment, the various elements of the tubular member 902 are coupledusing welding. The tubular member 902 may comprise a plurality oftubular elements that are coupled end to end. The various elements ofthe tubular member 915 may be coupled using any number of conventionalprocess such as, for example, threaded connections, welding or machinedfrom one piece. In a preferred embodiment, the various elements of thetubular member 915 are coupled using welding. The tubular member 915 maycomprise a plurality of tubular elements that are coupled end to end.The tubular members 902 and 915 may be coupled using any number ofconventional process such as, for example, threaded connections, weldingor machined from one piece.

The support member 904 preferably includes an innerstring adapter 916, afluid passage 918, an upper guide 920, and a coupling 922. Duringoperation of the apparatus 900, the support member 904 preferablysupports the apparatus 900 during movement of the apparatus 900 within awellbore. The support member 904 preferably has a substantially annularcross-section.

The support member 904 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfieldtubulars, low alloy steel, coiled tubing or stainless steel. In apreferred embodiment, the support member 904 is fabricated from lowalloy steel in order to optimally provide high yield strength.

The innerstring adaptor 916 preferably is coupled to and supported by aconventional drill string support from a surface location. Theinnerstring adaptor 916 may be coupled to a conventional drill stringsupport 971 by a threaded connection 970.

The fluid passage 918 is preferably used to convey fluids and othermaterials to and from the apparatus 900. In a preferred embodiment, thefluid passage 918 is fluidicly coupled to the fluid passage 952. In apreferred embodiment, the fluid passage 918 is used to convey hardenablefluidic sealing materials to and from the apparatus 900. In aparticularly preferred embodiment, the fluid passage 918 may include oneor more pressure relief passages (not illustrated) to release fluidpressure during positioning of the apparatus 900 within a wellbore. In apreferred embodiment, the fluid passage 918 is positioned along alongitudinal centerline of the apparatus 900. In a preferred embodiment,the fluid passage 918 is selected to permit the conveyance of hardenablefluidic materials at operating pressures ranging from about 0 to 9,000psi.

The upper guide 920 is coupled to an upper portion of the support member904. The upper guide 920 preferably is adapted to center the supportmember 904 within the tubular member 915. The upper guide 920 maycomprise any number of conventional guide members modified in accordancewith the teachings of the present disclosure. In a preferred embodiment,the upper guide 920 comprises an innerstring adapter available fromHalliburton Energy Services in Dallas, Tex. order to optimally guide theapparatus 900 within the tubular member 915.

The coupling 922 couples the support member 904 to the mandrel 906. Thecoupling 922 preferably comprises a conventional threaded connection.

The various elements of the support member 904 may be coupled using anynumber of conventional processes such as, for example, welding, threadedconnections or machined from one piece. In a preferred embodiment, thevarious elements of the support member 904 are coupled using threadedconnections.

The mandrel 906 preferably includes a retainer 924, a rubber cup 926, anexpansion cone 928, a lower cone retainer 930, a body of cement 932, alower guide 934, an extension sleeve 936, a spacer 938, a housing 940, asealing sleeve 942, an upper cone retainer 944, a lubricator mandrel946, a lubricator sleeve 948, a guide 950, and a fluid passage 952.

The retainer 924 is coupled to the lubricator mandrel 946, lubricatorsleeve 948, and the rubber cup 926. The retainer 924 couples the rubbercup 926 to the lubricator sleeve 948. The retainer 924 preferably has asubstantially annular cross-section. The retainer 924 may comprise anynumber of conventional commercially available retainers such as, forexample, slotted spring pins or roll pin.

The rubber cup 926 is coupled to the retainer 924, the lubricatormandrel 946, and the lubricator sleeve 948. The rubber cup 926 preventsthe entry of foreign materials into the interior region 972 of thetubular member 902 below the rubber cup 926. The rubber cup 926 maycomprise any number of conventional commercially available rubber cupssuch as, for example, TP cups or Selective Injection Packer (SIP) cup.In a preferred embodiment, the rubber cup 926 comprises a SIP cupavailable from Halliburton Energy Services in Dallas, Tex. in order tooptimally block foreign materials.

In a particularly preferred embodiment, a body of lubricant is furtherprovided in the interior region 972 of the tubular member 902 in orderto lubricate the interface between the exterior surface of the mandrel902 and the interior surface of the tubular members 902 and 915. Thelubricant may comprise any number of conventional commercially availablelubricants such as, for example, Lubriplate, chlorine based lubricants,oil based lubricants or Climax 1500 Antiseize (3100). In a preferredembodiment, the lubricant comprises Climax 1500 Antiseize (3100)available from Climax Lubricants and Equipment Co. in Houston, Tex. inorder to optimally provide lubrication to faciliate the extrusionprocess.

The expansion cone 928 is coupled to the lower cone retainer 930, thebody of cement 932, the lower guide 934, the extension sleeve 936, thehousing 940, and the upper cone retainer 944. In a preferred embodiment,during operation of the apparatus 900, the tubular members 902 and 915are extruded off of the outer surface of the expansion cone 928. In apreferred embodiment, axial movement of the expansion cone 928 isprevented by the lower cone retainer 930, housing 940 and the upper coneretainer 944. Inner radial movement of the expansion cone 928 isprevented by the body of cement 932, the housing 940, and the upper coneretainer 944.

The expansion cone 928 preferably has a substantially annular crosssection. The outside diameter of the expansion cone 928 is preferablytapered to provide a cone shape. The wall thickness of the expansioncone 928 may range, for example, from about 0.125 to 3 inches. In apreferred embodiment, the wall thickness of the expansion cone 928ranges from about 0.25 to 0.75 inches in order to optimally provideadequate compressive strength with minimal material. The maximum andminimum outside diameters of the expansion cone 928 may range, forexample, from about 1 to 47 inches. In a preferred embodiment, themaximum and minimum outside diameters of the expansion cone 928 rangefrom about 3.5 to 19 in order to optimally provide expansion ofgenerally available oilfield tubulars.

The expansion cone 928 may be fabricated from any number of conventionalcommercially available materials such as, for example, ceramic, toolsteel, titanium or low alloy steel. In a preferred embodiment, theexpansion cone 928 is fabricated from tool steel in order to optimallyprovide high strength and abrasion resistance. The surface hardness ofthe outer surface of the expansion cone 928 may range, for example, fromabout 50 Rockwell C to 70 Rockwell C. In a preferred embodiment, thesurface hardness of the outer surface of the expansion cone 928 rangesfrom about 58 Rockwell C to 62 Rockwell C in order to optimally providehigh yield strength. In a preferred embodiment, the expansion cone 928is heat treated to optimally provide a hard outer surface and aresilient interior body in order to optimally provide abrasionresistance and fracture toughness.

The lower cone retainer 930 is coupled to the expansion cone 928 and thehousing 940. In a preferred embodiment, axial movement of the expansioncone 928 is prevented by the lower cone retainer 930. Preferably, thelower cone retainer 930 has a substantially annular cross-section.

The lower cone retainer 930 may be fabricated from any number ofconventional commercially available materials such as, for example,ceramic, tool steel, titanium or low alloy steel. In a preferredembodiment, the lower cone retainer 930 is fabricated from tool steel inorder to optimally provide high strength and abrasion resistance. Thesurface hardness of the outer surface of the lower cone retainer 930 mayrange, for example, from about 50 Rockwell C to 70 Rockwell C. In apreferred embodiment, the surface hardness of the outer surface of thelower cone retainer 930 ranges from about 58 Rockwell C to 62 Rockwell Cin order to optimally provide high yield strength. In a preferredembodiment, the lower cone retainer 930 is heat treated to optimallyprovide a hard outer surface and a resilient interior body in order tooptimally provide abrasion resistance and fracture toughness.

In a preferred embodiment, the lower cone retainer 930 and the expansioncone 928 are formed as an integral one-piece element in order reduce thenumber of components and increase the overall strength of the apparatus.The outer surface of the lower cone retainer 930 preferably mates withthe inner surfaces of the tubular members 902 and 915.

The body of cement 932 is positioned within the interior of the mandrel906. The body of cement 932 provides an inner bearing structure for themandrel 906. The body of cement 932 further may be easily drilled outusing a conventional drill device. In this manner, the mandrel 906 maybe easily removed using a conventional drilling device.

The body of cement 932 may comprise any number of conventionalcommercially available cement compounds. Alternatively, aluminum, castiron or some other drillable metallic, composite, or aggregate materialmay be substituted for cement. The body of cement 932 preferably has asubstantially annular cross-section.

The lower guide 934 is coupled to the extension sleeve 936 and housing940. During operation of the apparatus 900, the lower guide 934preferably helps guide the movement of the mandrel 906 within thetubular member 902. The lower guide 934 preferably has a substantiallyannular cross-section.

The lower guide 934 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfieldtubulars, low alloy steel or stainless steel. In a preferred embodiment,the lower guide 934 is fabricated from low alloy steel in order tooptimally provide high yield strength. The outer surface of the lowerguide 934 preferably mates with the inner surface of the tubular member902 to provide a sliding fit.

The extension sleeve 936 is coupled to the lower guide 934 and thehousing 940. During operation of the apparatus 900, the extension sleeve936 preferably helps guide the movement of the mandrel 906 within thetubular member 902. The extension sleeve 936 preferably has asubstantially annular cross-section.

The extension sleeve 936 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield tubulars, low alloy steel or stainless steel. In a preferredembodiment, the extension sleeve 936 is fabricated from low alloy steelin order to optimally provide high yield strength. The outer surface ofthe extension sleeve 936 preferably mates with the inner surface of thetubular member 902 to provide a sliding fit. In a preferred embodiment,the extension sleeve 936 and the lower guide 934 are formed as anintegral one-piece element in order to minimize the number of componentsand increase the strength of the apparatus.

The spacer 938 is coupled to the sealing sleeve 942. The spacer 938preferably includes the fluid passage 952 and is adapted to mate withthe extension tube 960 of the shoe 908. In this manner, a plug or dartcan be conveyed from the surface through the fluid passages 918 and 952into the fluid passage 962. Preferably, the spacer 938 has asubstantially annular cross-section.

The spacer 938 may be fabricated from any number of conventionalcommercially available materials such as, for example, steel, aluminumor cast iron. In a preferred embodiment, the spacer 938 is fabricatedfrom aluminum in order to optimally provide drillability. The end of thespacer 938 preferably mates with the end of the extension tube 960. In apreferred embodiment, the spacer 938 and the sealing sleeve 942 areformed as an integral one-piece element in order to reduce the number ofcomponents and increase the strength of the apparatus.

The housing 940 is coupled to the lower guide 934, extension sleeve 936,expansion cone 928, body of cement 932, and lower cone retainer 930.During operation of the apparatus 900, the housing 940 preferablyprevents inner radial motion of the expansion cone 928. Preferably, thehousing 940 has a substantially annular cross-section.

The housing 940 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfieldtubulars, low alloy steel or stainless steel. In a preferred embodiment,the housing 940 is fabricated from low alloy steel in order to optimallyprovide high yield strength. In a preferred embodiment, the lower guide934, extension sleeve 936 and housing 940 are formed as an integralone-piece element in order to minimize the number of components andincrease the strength of the apparatus.

In a particularly preferred embodiment, the interior surface of thehousing 940 includes one or more protrusions to faciliate the connectionbetween the housing 940 and the body of cement 932.

The sealing sleeve 942 is coupled to the support member 904, the body ofcement 932, the spacer 938, and the upper cone retainer 944. Duringoperation of the apparatus, the sealing sleeve 942 preferably providessupport for the mandrel 906. The sealing sleeve 942 is preferablycoupled to the support member 904 using the coupling 922. Preferably,the sealing sleeve 942 has a substantially annular cross-section.

The sealing sleeve 942 may be fabricated from any number of conventionalcommercially available materials such as, for example, steel, aluminumor cast iron. In a preferred embodiment, the sealing sleeve 942 isfabricated from aluminum in order to optimally provide drillability ofthe sealing sleeve 942.

In a particularly preferred embodiment, the outer surface of the sealingsleeve 942 includes one or more protrusions to faciliate the connectionbetween the sealing sleeve 942 and the body of cement 932.

In a particularly preferred embodiment, the spacer 938 and the sealingsleeve 942 are integrally formed as a one-piece element in order tominimize the number of components.

The upper cone retainer 944 is coupled to the expansion cone 928, thesealing sleeve 942, and the body of cement 932. During operation of theapparatus 900, the upper cone retainer 944 preferably prevents axialmotion of the expansion cone 928. Preferably, the upper cone retainer944 has a substantially annular cross-section.

The upper cone retainer 944 may be fabricated from any number ofconventional commercially available materials such as, for example,steel, aluminum or cast iron. In a preferred embodiment, the upper coneretainer 944 is fabricated from aluminum in order to optimally providedrillability of the upper cone retainer 944.

In a particularly preferred embodiment, the upper cone retainer 944 hasa cross-sectional shape designed to provide increased rigidity. In aparticularly preferred embodiment, the upper cone retainer 944 has across-sectional shape that is substantially I-shaped to provideincreased rigidity and minimize the amount of material that would haveto be drilled out.

The lubricator mandrel 946 is coupled to the retainer 924, the rubbercup 926, the upper cone retainer 944, the lubricator sleeve 948, and theguide 950. During operation of the apparatus 900, the lubricator mandrel946 preferably contains the body of lubricant in the annular region 972for lubricating the interface between the mandrel 906 and the tubularmember 902. Preferably, the lubricator mandrel 946 has a substantiallyannular cross-section.

The lubricator mandrel 946 may be fabricated from any number ofconventional commercially available materials such as, for example,steel, aluminum or cast iron. In a preferred embodiment, the lubricatormandrel 946 is fabricated from aluminum in order to optimally providedrillability of the lubricator mandrel 946.

The lubricator sleeve 948 is coupled to the lubricator mandrel 946, theretainer 924, the rubber cup 926, the upper cone retainer 944, thelubricator sleeve 948, and the guide 950. During operation of theapparatus 900, the lubricator sleeve 948 preferably supports the rubbercup 926. Preferably, the lubricator sleeve 948 has a substantiallyannular cross-section.

The lubricator sleeve 948 may be fabricated from any number ofconventional commercially available materials such as, for example,steel, aluminum or cast iron. In a preferred embodiment, the lubricatorsleeve 948 is fabricated from aluminum in order to optimally providedrillability of the lubricator sleeve 948.

As illustrated in FIG. 9c, the lubricator sleeve 948 is supported by thelubricator mandrel 946. The lubricator sleeve 948 in turn supports therubber cup 926. The retainer 924 couples the rubber cup 926 to thelubricator sleeve 948. In a preferred embodiment, seals 949 a and 949 bare provided between the lubricator mandrel 946, lubricator sleeve 948,and rubber cup 926 in order to optimally seal off the interior region972 of the tubular member 902.

The guide 950 is coupled to the lubricator mandrel 946, the retainer924, and the lubricator sleeve 948. During operation of the apparatus900, the guide 950 preferably guides the apparatus on the support member904. Preferably, the guide 950 has a substantially annularcross-section.

The guide 950 may be fabricated from any number of conventionalcommercially available materials such as, for example, steel, aluminumor cast iron. In a preferred embodiment, the guide 950 is fabricatedfrom aluminum order to optimally provide drillability of the guide 950.

The fluid passage 952 is coupled to the mandrel 906. During operation ofthe apparatus, the fluid passage 952 preferably conveys hardenablefluidic materials. In a preferred embodiment, the fluid passage 952 ispositioned about the centerline of the apparatus 900. In a particularlypreferred embodiment, the fluid passage 952 is adapted to conveyhardenable fluidic materials at pressures and flow rate ranging fromabout 0 to 9,000 psi and 0 to 3,000 gallons/min in order to optimallyprovide pressures and flow rates to displace and circulate fluids duringthe installation of the apparatus 900.

The various elements of the mandrel 906 may be coupled using any numberof conventional process such as, for example, threaded connections,welded connections or cementing. In a preferred embodiment, the variouselements of the mandrel 906 are coupled using threaded connections andcementing.

The shoe 908 preferably includes a housing 954, a body of cement 956, asealing sleeve 958, an extension tube 960, a fluid passage 962, and oneor more outlet jets 964.

The housing 954 is coupled to the body of cement 956 and the lowerportion 914 of the tubular member 902. During operation of the apparatus900, the housing 954 preferably couples the lower portion of the tubularmember 902 to the shoe 908 to facilitate the extrusion and positioningof the tubular member 902. Preferably, the housing 954 has asubstantially annular cross-section.

The housing 954 may be fabricated from any number of conventionalcommercially available materials such as, for example, steel oraluminum. In a preferred embodiment, the housing 954 is fabricated fromaluminum in order to optimally provide drillability of the housing 954.

In a particularly preferred embodiment, the interior surface of thehousing 954 includes one or more protrusions to faciliate the connectionbetween the body of cement 956 and the housing 954.

The body of cement 956 is coupled to the housing 954, and the sealingsleeve 958. In a preferred embodiment, the composition of the body ofcement 956 is selected to permit the body of cement to be easily drilledout using conventional drilling machines and processes.

The composition of the body of cement 956 may include any number ofconventional cement compositions. In an alternative embodiment, adrillable material such as, for example, aluminum or iron may besubstituted for the body of cement 956.

The sealing sleeve 958 is coupled to the body of cement 956, theextension tube 960, the fluid passage 962, and one or more outlet jets964. During operation of the apparatus 900, the sealing sleeve 958preferably is adapted to convey a hardenable fluidic material from thefluid passage 952 into the fluid passage 962 and then into the outletjets 964 in order to inject the hardenable fluidic material into anannular region external to the tubular member 902. In a preferredembodiment, during operation of the apparatus 900, the sealing sleeve958 further includes an inlet geometry that permits a conventional plugor dart 974 to become lodged in the inlet of the sealing sleeve 958. Inthis manner, the fluid passage 962 may be blocked thereby fluidiclyisolating the interior region 966 of the tubular member 902.

In a preferred embodiment, the sealing sleeve 958 has a substantiallyannular cross-section. The sealing sleeve 958 may be fabricated from anynumber of conventional commercially available materials such as, forexample, steel, aluminum or cast iron. In a preferred embodiment, thesealing sleeve 958 is fabricated from aluminum in order to optimallyprovide drillability of the sealing sleeve 958.

The extension tube 960 is coupled to the sealing sleeve 958, the fluidpassage 962, and one or more outlet jets 964. During operation of theapparatus 900, the extension tube 960 preferably is adapted to convey ahardenable fluidic material from the fluid passage 952 into the fluidpassage 962 and then into the outlet jets 964 in order to inject thehardenable fluidic material into an annular region external to thetubular member 902. In a preferred embodiment, during operation of theapparatus 900, the sealing sleeve 960 further includes an inlet geometrythat permits a conventional plug or dart 974 to become lodged in theinlet of the sealing sleeve 958. In this manner, the fluid passage 962is blocked thereby fluidicly isolating the interior region 966 of thetubular member 902. In a preferred embodiment, one end of the extensiontube 960 mates with one end of the spacer 938 in order to optimallyfaciliate the transfer of material between the two.

In a preferred embodiment, the extension tube 960 has a substantiallyannular cross-section. The extension tube 960 may be fabricated from anynumber of conventional commercially available materials such as, forexample, steel, aluminum or cast iron. In a preferred embodiment, theextension tube 960 is fabricated from aluminum in order to optimallyprovide drillability of the extension tube 960.

The fluid passage 962 is coupled to the sealing sleeve 958, theextension tube 960, and one or more outlet jets 964. During operation ofthe apparatus 900, the fluid passage 962 is preferably conveyshardenable fluidic materials. In a preferred embodiment, the fluidpassage 962 is positioned about the centerline of the apparatus 900. Ina particularly preferred embodiment, the fluid passage 962 is adapted toconvey hardenable fluidic materials at pressures and flow rate rangingfrom about 0 to 9,000 psi and 0 to 3,000 gallons/min in order tooptimally provide fluids at operationally efficient rates.

The outlet jets 964 are coupled to the sealing sleeve 958, the extensiontube 960, and the fluid passage 962. During operation of the apparatus900, the outlet jets 964 preferably convey hardenable fluidic materialfrom the fluid passage 962 to the region exterior of the apparatus 900.In a preferred embodiment, the shoe 908 includes a plurality of outletjets 964.

In a preferred embodiment, the outlet jets 964 comprise passages drilledin the housing 954 and the body of cement 956 in order to simplify theconstruction of the apparatus 900.

The various elements of the shoe 908 may be coupled using any number ofconventional process such as, for example, threaded connections, cementor machined from one piece of material. In a preferred embodiment, thevarious elements of the shoe 908 are coupled using cement.

In a preferred embodiment, the assembly 900 is operated substantially asdescribed above with reference to FIGS. 1-8 to create a new section ofcasing in a wellbore or to repair a wellbore casing or pipeline.

In particular, in order to extend a wellbore into a subterraneanformation, a drill string is used in a well known manner to drill outmaterial from the subterranean formation to form a new section.

The apparatus 900 for forming a wellbore casing in a subterraneanformation is then positioned in the new section of the wellbore. In aparticularly preferred embodiment, the apparatus 900 includes thetubular member 915. In a preferred embodiment, a hardenable fluidicsealing hardenable fluidic sealing material is then pumped from asurface location into the fluid passage 918. The hardenable fluidicsealing material then passes from the fluid passage 918 into theinterior region 966 of the tubular member 902 below the mandrel 906. Thehardenable fluidic sealing material then passes from the interior region966 into the fluid passage 962. The hardenable fluidic sealing materialthen exits the apparatus 900 via the outlet jets 964 and fills anannular region between the exterior of the tubular member 902 and theinterior wall of the new section of the wellbore. Continued pumping ofthe hardenable fluidic sealing material causes the material to fill upat least a portion of the annular region.

The hardenable fluidic sealing material is preferably pumped into theannular region at pressures and flow rates ranging, for example, fromabout 0 to 5,000 psi and 0 to 1,500 gallons/min, respectively. In apreferred embodiment, the hardenable fluidic sealing material is pumpedinto the annular region at pressures and flow rates that are designedfor the specific wellbore section in order to optimize the displacementof the hardenable fluidic sealing material while not creating highenough circulating pressures such that circulation might be lost andthat could cause the wellbore to collapse. The optimum pressures andflow rates are preferably determined using conventional empiricalmethods.

The hardenable fluidic sealing material may comprise any number ofconventional commercially available hardenable fluidic sealing materialssuch as, for example, slag mix, cement or epoxy. In a preferredembodiment, the hardenable fluidic sealing material comprises blendedcements designed specifically for the well section being lined availablefrom Halliburton Energy Services in Dallas, Tex. in order to optimallyprovide support for the new tubular member while also maintainingoptimal flow characteristics so as to minimize operational difficultiesduring the displacement of the cement in the annular region. The optimumcomposition of the blended cements is preferably determined usingconventional empirical methods.

The annular region preferably is filled with the hardenable fluidicsealing material in sufficient quantities to ensure that, upon radialexpansion of the tubular member 902, the annular region of the newsection of the wellbore will be filled with hardenable material.

Once the annular region has been adequately filled with hardenablefluidic sealing material, a plug or dart 974, or other similar device,preferably is introduced into the fluid passage 962 thereby fluidiclyisolating the interior region 966 of the tubular member 902 from theexternal annular region. In a preferred embodiment, a non hardenablefluidic material is then pumped into the interior region 966 causing theinterior region 966 to pressurize. In a particularly preferredembodiment, the plug or dart 974, or other similar device, preferably isintroduced into the fluid passage 962 by introducing the plug or dart974, or other similar device into the non hardenable fluidic material.In this manner, the amount of cured material within the interior of thetubular members 902 and 915 is minimized.

Once the interior region 966 becomes sufficiently pressurized, thetubular members 902 and 915 are extruded off of the mandrel 906. Themandrel 906 may be fixed or it may be expandible. During the extrusionprocess, the mandrel 906 is raised out of the expanded portions of thetubular members 902 and 915 using the support member 904. During thisextrusion process, the shoe 908 is preferably substantially stationary.

The plug or dart 974 is preferably placed into the fluid passage 962 byintroducing the plug or dart 974 into the fluid passage 918 at a surfacelocation in a conventional manner. The plug or dart 974 may comprise anynumber of conventional commercially available devices for plugging afluid passage such as, for example, Multiple Stage Cementer (MSC)latch-down plug, Omega latch-down plug or three-wiper latch down plugmodified in accordance with the teachings of the present disclosure. Ina preferred embodiment, the plug or dart 974 comprises a MSC latch-downplug available from Halliburton Energy Services in Dallas, Tex.

After placement of the plug or dart 974 in the fluid passage 962, thenon hardenable fluidic material is preferably pumped into the interiorregion 966 at pressures and flow rates ranging from approximately 500 to9,000 psi and 40 to 3,000 gallons/min in order to optimally extrude thetubular members 902 and 915 off of the mandrel 906.

For typical tubular members 902 and 915, the extrusion of the tubularmembers 902 and 915 off of the expandable mandrel will begin when thepressure of the interior region 966 reaches approximately 500 to 9,000psi. In a preferred embodiment, the extrusion of the tubular members 902and 915 off of the mandrel 906 begins when the pressure of the interiorregion 966 reaches approximately 1,200 to 8,500 psi with a flow rate ofabout 40 to 1250 gallons/minute.

During the extrusion process, the mandrel 906 may be raised out of theexpanded portions of the tubular members 902 and 915 at rates ranging,for example, from about 0 to 5 ft/sec. In a preferred embodiment, duringthe extrusion process, the mandrel 906 is raised out of the expandedportions of the tubular members 902 and 915 at rates ranging from about0 to 2 ft/sec in order to optimally provide pulling speed fast enough topermit efficient operation and permit full expansion of the tubularmembers 902 and 915 prior to curing of the hardenable fluidic sealingmaterial; but not so fast that timely adjustment of operating parametersduring operation is prevented.

When the upper end portion of the tubular member 915 is extruded off ofthe mandrel 906, the outer surface of the upper end portion of thetubular member 915 will preferably contact the interior surface of thelower end portion of the existing casing to form an fluid tightoverlapping joint. The contact pressure of the overlapping joint mayrange, for example, from approximately 50 to 20,000 psi. In a preferredembodiment, the contact pressure of the overlapping joint between theupper end of the tubular member 915 and the existing section of wellborecasing ranges from approximately 400 to 10,000 psi in order to optimallyprovide contact pressure to activate the sealing members and provideoptimal resistance such that the tubular member 915 and existingwellbore casing will carry typical tensile and compressive loads.

In a preferred embodiment, the operating pressure and flow rate of thenon hardenable fluidic material will be controllably ramped down whenthe mandrel 906 reaches the upper end portion of the tubular member 915.In this manner, the sudden release of pressure caused by the completeextrusion of the tubular member 915 off of the expandable mandrel 906can be minimized. In a preferred embodiment, the operating pressure isreduced in a substantially linear fashion from 100% to about 10% duringthe end of the extrusion process beginning when the mandrel 906 hascompleted approximately all but about the last 5 feet of the extrusionprocess.

In an alternative preferred embodiment, the operating pressure and/orflow rate of the hardenable fluidic sealing material and/or the nonhardenable fluidic material are controlled during all phases of theoperation of the apparatus 900 to minimize shock.

Alternatively, or in combination, a shock absorber is provided in thesupport member 904 in order to absorb the shock caused by the suddenrelease of pressure.

Alternatively, or in combination, a mandrel catching structure isprovided above the support member 904 in order to catch or at leastdecelerate the mandrel 906.

Once the extrusion process is completed, the mandrel 906 is removed fromthe wellbore. In a preferred embodiment, either before or after theremoval of the mandrel 906, the integrity of the fluidic seal of theoverlapping joint between the upper portion of the tubular member 915and the lower portion of the existing casing is tested usingconventional methods. If the fluidic seal of the overlapping jointbetween the upper portion of the tubular member 915 and the lowerportion of the existing casing is satisfactory, then the uncured portionof any of the hardenable fluidic sealing material within the expandedtubular member 915 is then removed in a conventional manner. Thehardenable fluidic sealing material within the annular region betweenthe expanded tubular member 915 and the existing casing and new sectionof wellbore is then allowed to cure.

Preferably any remaining cured hardenable fluidic sealing materialwithin the interior of the expanded tubular members 902 and 915 is thenremoved in a conventional manner using a conventional drill string. Theresulting new section of casing preferably includes the expanded tubularmembers 902 and 915 and an outer annular layer of cured hardenablefluidic sealing material. The bottom portion of the apparatus 900comprising the shoe 908 may then be removed by drilling out the shoe 908using conventional drilling methods.

In an alternative embodiment, during the extrusion process, it may benecessary to remove the entire apparatus 900 from the interior of thewellbore due to a malfunction. In this circumstance, a conventionaldrill string is used to drill out the interior sections of the apparatus900 in order to facilitate the removal of the remaining sections. In apreferred embodiment, the interior elements of the apparatus 900 arefabricated from materials such as, for example, cement and aluminum,that permit a conventional drill string to be employed to drill out theinterior components.

In particular, in a preferred embodiment, the composition of theinterior sections of the mandrel 906 and shoe 908, including one or moreof the body of cement 932, the spacer 938, the sealing sleeve 942, theupper cone retainer 944, the lubricator mandrel 946, the lubricatorsleeve 948, the guide 950, the housing 954, the body of cement 956, thesealing sleeve 958, and the extension tube 960, are selected to permitat least some of these components to be drilled out using conventionaldrilling methods and apparatus. In this manner, in the event of amalfunction downhole, the apparatus 900 may be easily removed from thewellbore.

Referring now to FIGS. 10a, 10 b, 10 c, 10 d, 10 e, 10 f, and 10 g amethod and apparatus for creating a tie-back liner in a wellbore willnow be described. As illustrated in FIG. 10a, a wellbore 1000 positionedin a subterranean formation 1002 includes a first casing 1004 and asecond casing 1006.

The first casing 1004 preferably includes a tubular liner 1008 and acement annulus 1010. The second casing 1006 preferably includes atubular liner 1012 and a cement annulus 1014. In a preferred embodiment,the second casing 1006 is formed by expanding a tubular membersubstantially as described above with reference to FIGS. 1-9c or belowwith reference to FIGS. 11a-11 f.

In a particularly preferred embodiment, an upper portion of the tubularliner 1012 overlaps with a lower portion of the tubular liner 1008. In aparticularly preferred embodiment, an outer surface of the upper portionof the tubular liner 1012 includes one or more sealing members 1016 forproviding a fluidic seal between the tubular liners 1008 and 1012.

Referring to FIG. 10b, in order to create a tie-back liner that extendsfrom the overlap between the first and second casings, 1004 and 1006, anapparatus 1100 is preferably provided that includes an expandablemandrel or pig 1105, a tubular member 1110, a shoe 1115, one or more cupseals 1120, a fluid passage 1130, a fluid passage 1135, one or morefluid passages 1140, seals 1145, and a support member 1150.

The expandable mandrel or pig 1105 is coupled to and supported by thesupport member 1150. The expandable mandrel 1105 is preferably adaptedto controllably expand in a radial direction. The expandable mandrel1105 may comprise any number of conventional commercially availableexpandable mandrels modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the expandable mandrel1105 comprises a hydraulic expansion tool substantially as disclosed inU.S. Pat. No. 5,348,095, the disclosure of which is incorporated hereinby reference, modified in accordance with the teachings of the presentdisclosure.

The tubular member 1110 is coupled to and supported by the expandablemandrel 1105. The tubular member 1105 is expanded in the radialdirection and extruded off of the expandable mandrel 1105. The tubularmember 1110 may be fabricated from any number of materials such as, forexample, Oilfield Country Tubular Goods, 13 chromium tubing or plasticpiping. In a preferred embodiment, the tubular member 1110 is fabricatedfrom Oilfield Country Tubular Goods.

The inner and outer diameters of the tubular member 1110 may range, forexample, from approximately 0.75 to 47 inches and 1.05 to 48 inches,respectively. In a preferred embodiment, the inner and outer diametersof the tubular member 1110 range from about 3 to 15.5 inches and 3.5 to16 inches, respectively in order to optimally provide coverage fortypical oilfield casing sizes. The tubular member 1110 preferablycomprises a solid member.

In a preferred embodiment, the upper end portion of the tubular member1110 is slotted, perforated, or otherwise modified to catch or slow downthe mandrel 1105 when it completes the extrusion of tubular member 1110.In a preferred embodiment, the length of the tubular member 1110 islimited to minimize the possibility of buckling. For typical tubularmember 1110 materials, the length of the tubular member 1110 ispreferably limited to between about 40 to 20,000 feet in length.

The shoe 1115 is coupled to the expandable mandrel 1105 and the tubularmember 1110. The shoe 1115 includes the fluid passage 1135. The shoe1115 may comprise any number of conventional commercially availableshoes such as, for example, Super Seal II float shoe, Super Seal IIDown-Jet float shoe or a guide shoe with a sealing sleeve for a latchdown plug modified in accordance with the teachings of the presentdisclosure. In a preferred embodiment, the shoe 1115 comprises analuminum down-jet guide shoe with a sealing sleeve for a latch-down plugwith side ports radiating off of the exit flow port available fromHalliburton Energy Services in Dallas, Tex., modified in accordance withthe teachings of the present disclosure, in order to optimally guide thetubular member 1100 to the overlap between the tubular member 1100 andthe casing 1012, optimally fluidicly isolate the interior of the tubularmember 1100 after the latch down plug has seated, and optimally permitdrilling out of the shoe 1115 after completion of the expansion andcementing operations.

In a preferred embodiment, the shoe 1115 includes one or more sideoutlet ports 1140 in fluidic communication with the fluid passage 1135.In this manner, the shoe 1115 injects hardenable fluidic sealingmaterial into the region outside the shoe 1115 and tubular member 1110.In a preferred embodiment, the shoe 1115 includes one or more of thefluid passages 1140 each having an inlet geometry that can receive adart and/or a ball sealing member. In this manner, the fluid passages1140 can be sealed off by introducing a plug, dart and/or ball sealingelements into the fluid passage 1130.

The cup seal 1120 is coupled to and supported by the support member1150. The cup seal 1120 prevents foreign materials from entering theinterior region of the tubular member 1110 adjacent to the expandablemandrel 1105. The cup seal 1120 may comprise any number of conventionalcommercially available cup seals such as, for example, TP cups orSelective Injection Packer (SIP) cups modified in accordance with theteachings of the present disclosure. In a preferred embodiment, the cupseal 1120 comprises a SIP cup, available from Halliburton EnergyServices in Dallas, Tex. in order to optimally provide a barrier todebris and contain a body of lubricant.

The fluid passage 1130 permits fluidic materials to be transported toand from the interior region of the tubular member 1110 below theexpandable mandrel 1105. The fluid passage 1130 is coupled to andpositioned within the support member 1150 and the expandable mandrel1105. The fluid passage 1130 preferably extends from a position adjacentto the surface to the bottom of the expandable mandrel 1105. The fluidpassage 1130 is preferably positioned along a centerline of theapparatus 1100. The fluid passage 1130 is preferably selected totransport materials such as cement, drilling mud or epoxies at flowrates and pressures ranging from about 0 to 3,000 gallons/minute and 0to 9,000 psi in order to optimally provide sufficient operatingpressures to circulate fluids at operationally efficient rates.

The fluid passage 1135 permits fluidic materials to be transmitted fromfluid passage 1130 to the interior of the tubular member 1110 below themandrel 1105.

The fluid passages 1140 permits fluidic materials to be transported toand from the region exterior to the tubular member 1110 and shoe 1115.The fluid passages 1140 are coupled to and positioned within the shoe1115 in fluidic communication with the interior region of the tubularmember 1110 below the expandable mandrel 1105. The fluid passages 1140preferably have a cross-sectional shape that permits a plug, or othersimilar device, to be placed in the fluid passages 1140 to thereby blockfurther passage of fluidic materials. In this manner, the interiorregion of the tubular member 1110 below the expandable mandrel 1105 canbe fluidicly isolated from the region exterior to the tubular member1105. This permits the interior region of the tubular member 1110 belowthe expandable mandrel 1105 to be pressurized.

The fluid passages 1140 are preferably positioned along the periphery ofthe shoe 1115. The fluid passages 1140 are preferably selected to conveymaterials such as cement, drilling mud or epoxies at flow rates andpressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000psi in order to optimally fill the annular region between the tubularmember 1110 and the tubular liner 1008 with fluidic materials. In apreferred embodiment, the fluid passages 1140 include an inlet geometrythat can receive a dart and/or a ball sealing member. In this manner,the fluid passages 1140 can be sealed off by introducing a plug, dartand/or ball sealing elements into the fluid passage 1130. In a preferredembodiment, the apparatus 1100 includes a plurality of fluid passage1140.

In an alternative embodiment, the base of the shoe 1115 includes asingle inlet passage coupled to the fluid passages 1140 that is adaptedto receive a plug, or other similar device, to permit the interiorregion of the tubular member 1110 to be fluidicly isolated from theexterior of the tubular member 1110.

The seals 1145 are coupled to and supported by a lower end portion ofthe tubular member 1110. The seals 1145 are further positioned on anouter surface of the lower end portion of the tubular member 1110. Theseals 1145 permit the overlapping joint between the upper end portion ofthe casing 1012 and the lower end portion of the tubular member 1110 tobe fluidicly sealed.

The seals 1145 may comprise any number of conventional commerciallyavailable seals such as, for example, lead, rubber, Teflon or epoxyseals modified in accordance with the teachings of the presentdisclosure. In a preferred embodiment, the seals 1145 comprise sealsmolded from Stratalock epoxy available from Halliburton Energy Servicesin Dallas, Tex. in order to optimally provide a hydraulic seal in theoverlapping joint and optimally provide load carrying capacity towithstand the range of typical tensile and compressive loads.

In a preferred embodiment, the seals 1145 are selected to optimallyprovide a sufficient frictional force to support the expanded tubularmember 1110 from the tubular liner 1008. In a preferred embodiment, thefrictional force provided by the seals 1145 ranges from about 1,000 to1,000,000 lbf in tension and compression in order to optimally supportthe expanded tubular member 1110.

The support member 1150 is coupled to the expandable mandrel 1105,tubular member 1110, shoe 1115, and seal 1120. The support member 1150preferably comprises an annular member having sufficient strength tocarry the apparatus 1100 into the wellbore 1000. In a preferredembodiment, the support member 1150 further includes one or moreconventional centralizers (not illustrated) to help stabilize thetubular member 1110.

In a preferred embodiment, a quantity of lubricant 1150 is provided inthe annular region above the expandable mandrel 1105 within the interiorof the tubular member 1110. In this manner, the extrusion of the tubularmember 1110 off of the is expandable mandrel 1105 is facilitated. Thelubricant 1150 may comprise any number of conventional commerciallyavailable lubricants such as, for example, Lubriplate, chlorine basedlubricants or Climax 1500 Antiseize (3100). In a preferred embodiment,the lubricant 1150 comprises Climax 1500 Antiseize (3100) available fromClimax Lubricants and Equipment Co. in Houston, Tex. in order tooptimally provide lubrication for the extrusion process.

In a preferred embodiment, the support member 1150 is thoroughly cleanedprior to assembly to the remaining portions of the apparatus 1100. Inthis manner, the introduction of foreign material into the apparatus1100 is minimized. This minimizes the possibility of foreign materialclogging the various flow passages and valves of the apparatus 1100 andto ensure that no foreign material interferes with the expansion mandrel1105 during the extrusion process.

In a particularly preferred embodiment, the apparatus 1100 includes apacker 1155 coupled to the bottom section of the shoe 1115 for fluidiclyisolating the region of the wellbore 1000 below the apparatus 1100. Inthis manner, fluidic materials are prevented from entering the region ofthe wellbore 1000 below the apparatus 1100. The packer 1155 may compriseany number of conventional commercially available packers such as, forexample, EZ Drill Packer, EZ SV Packer or a drillable cement retainer.In a preferred embodiment, the packer 1155 comprises an EZ Drill Packeravailable from Halliburton Energy Services in Dallas, Tex. In analternative embodiment, a high gel strength pill may be set below thetie-back in place of the packer 1155. In another alternative embodiment,the packer 1155 may be omitted.

In a preferred embodiment, before or after positioning the apparatus1100 within the wellbore 1100, a couple of wellbore volumes arecirculated in order to ensure that no foreign materials are locatedwithin the wellbore 1000 that might clog up the various flow passagesand valves of the apparatus 1100 and to ensure that no foreign materialinterferes with the operation of the expansion mandrel 1105.

As illustrated in FIG. 10c, a hardenable fluidic sealing material 1160is then pumped from a surface location into the fluid passage 1130. Thematerial 1160 then passes from the fluid passage 1130 into the interiorregion of the tubular member 1110 below the expandable mandrel 1105. Thematerial 1160 then passes from the interior region of the tubular member1110 into the fluid passages 1140. The material 1160 then exits theapparatus 1100 and fills the annular region between the exterior of thetubular member 1110 and the interior wall of the tubular liner 1008.Continued pumping of the material 1160 causes the material 1160 to fillup at least a portion of the annular region.

The material 1160 may be pumped into the annular region at pressures andflow rates ranging, for example, from about 0 to 5,000 psi and 0 to1,500 gallons/min, respectively. In a preferred embodiment, the material1160 is pumped into the annular region at pressures and flow ratesspecifically designed for the casing sizes being run, the annular spacesbeing filled, the pumping equipment available, and the properties of thefluid being pumped. The optimum flow rates and pressures are preferablycalculated using conventional empirical methods.

The hardenable fluidic sealing material 1160 may comprise any number ofconventional commercially available hardenable fluidic sealing materialssuch as, for example, slag mix, cement or epoxy. In a preferredembodiment, the hardenable fluidic sealing material 1160 comprisesblended cements specifically designed for well section being tied-back,available from Halliburton Energy Services in Dallas, Tex. in order tooptimally provide proper support for the tubular member 1110 whilemaintaining optimum flow characteristics so as to minimize operationaldifficulties during the displacement of cement in the annular region.The optimum blend of the blended cements are preferably determined usingconventional empirical methods.

The annular region may be filled with the material 1160 in sufficientquantities to ensure that, upon radial expansion of the tubular member1110, the annular region will be filled with material 1160.

As illustrated in FIG. 10d, once the annular region has been adequatelyfilled with material 1160, one or more plugs 1165, or other similardevices, preferably are introduced into the fluid passages 1140 therebyfluidicly isolating the interior region of the tubular member 1110 fromthe annular region external to the tubular member 1110. In a preferredembodiment, a non hardenable fluidic material 1161 is then pumped intothe interior region of the tubular member 1110 below the mandrel 1105causing the interior region to pressurize. In a particularly preferredembodiment, the one or more plugs 1165, or other similar devices, areintroduced into the fluid passage 1140 with the introduction of the nonhardenable fluidic material. In this manner, the amount of hardenablefluidic material within the interior of the tubular member 1110 isminimized.

As illustrated in FIG. 10e, once the interior region becomessufficiently pressurized, the tubular member 1110 is extruded off of theexpandable mandrel 1105. During the extrusion process, the expandablemandrel 1105 is raised out of the expanded portion of the tubular member1110.

The plugs 1165 are preferably placed into the fluid passages 1140 byintroducing the plugs 1165 into the fluid passage 1130 at a surfacelocation in a conventional manner. The plugs 1165 may comprise anynumber of conventional commercially available devices from plugging afluid passage such as, for example, brass balls, plugs, rubber balls, ordarts modified in accordance with the teachings of the presentdisclosure.

In a preferred embodiment, the plugs 1165 comprise low density rubberballs. In an alternative embodiment, for a shoe 1105 having a commoncentral inlet passage, the plugs 1165 comprise a single latch down dart.

After placement of the plugs 1165 in the fluid passages 1140, the nonhardenable fluidic material 1161 is preferably pumped into the interiorregion of the tubular member 1110 below the mandrel 1105 at pressuresand flow rates ranging from approximately 500 to 9,000 psi and 40 to3,000 gallons/min. In a preferred embodiment, after placement of theplugs 1165 in the fluid passages 1140, the non hardenable fluidicmaterial 1161 is preferably pumped into the interior region of thetubular member 1110 below the mandrel 1105 at pressures and flow ratesranging from approximately 1200 to 8500 psi and 40 to 1250 gallons/minin order to optimally provide extrusion of typical tubulars.

For typical tubular members 1110, the extrusion of the tubular member1110 off of the expandable mandrel 1105 will begin when the pressure ofthe interior region of the tubular member 1110 below the mandrel 1105reaches, for example, approximately 1200 to 8500 psi. In a preferredembodiment, the extrusion of the tubular member 1110 off of theexpandable mandrel 1105 begins when the pressure of the interior regionof the tubular member 1110 below the mandrel 1105 reaches approximately1200 to 8500 psi.

During the extrusion process, the expandable mandrel 1105 may be raisedout of the expanded portion of the tubular member 1110 at rates ranging,for example, from about 0 to 5 ft/sec. In a preferred embodiment, duringthe extrusion process, the expandable mandrel 1105 is raised out of theexpanded portion of the tubular member 1110 at rates ranging from about0 to 2 ft/sec in order to optimally provide permit adjustment ofoperational parameters, and optimally ensure that the extrusion processwill be completed before the material 1160 cures.

In a preferred embodiment, at least a portion 1180 of the tubular member1110 has an internal diameter less than the outside diameter of themandrel 1105. In this manner, when the mandrel 1105 expands the section1180 of the tubular member 1110, at least a portion of the expandedsection 1180 effects a seal with at least the wellbore casing 1012. In aparticularly preferred embodiment, the seal is effected by compressingthe seals 1016 between the expanded section 1180 and the wellbore casing1012. In a preferred embodiment, the contact pressure of the jointbetween the expanded section 1180 of the tubular member 1110 and thecasing 1012 ranges from about 500 to 10,000 psi in order to optimallyprovide pressure to activate the sealing members 1145 and provideoptimal resistance to ensure that the joint will withstand typicalextremes of tensile and compressive loads.

In an alternative preferred embodiment, substantially all of the entirelength of the tubular member 1110 has an internal diameter less than theoutside diameter of the mandrel 1105. In this manner, extrusion of thetubular member 1110 by the mandrel 1105 results in contact betweensubstantially all of the expanded tubular member 1110 and the existingcasing 1008. In a preferred embodiment, the contact pressure of thejoint between the expanded tubular member 1110 and the casings 1008 and1012 ranges from about 500 to 10,000 psi in order to optimally providepressure to activate the sealing members 1145 and provide optimalresistance to ensure that the joint will withstand typical extremes oftensile and compressive loads.

In a preferred embodiment, the operating pressure and flow rate of thematerial 1161 is controllably ramped down when the expandable mandrel1105 reaches the upper end portion of the tubular member 1110. In thismanner, the sudden release of pressure caused by the complete extrusionof the tubular member 1110 off of the expandable mandrel 1105 can beminimized. In a preferred embodiment, the operating pressure of thefluidic material 1161 is reduced in a substantially linear fashion from100% to about 10% during the end of the extrusion process beginning whenthe mandrel 1105 has completed approximately all but about 5 feet of theextrusion process.

Alternatively, or in combination, a shock absorber is provided in thesupport member 1150 in order to absorb the shock caused by the suddenrelease of pressure.

Alternatively, or in combination, a mandrel catching structure isprovided in the upper end portion of the tubular member 1110 in order tocatch or at least decelerate the mandrel 1105.

Referring to FIG. 10f, once the extrusion process is completed, theexpandable mandrel 1105 is removed from the wellbore 1000. In apreferred embodiment, either before or after the removal of theexpandable mandrel 1105, the integrity of the fluidic seal of the jointbetween the upper portion of the tubular member 1110 and the upperportion of the tubular liner 1108 is tested using conventional methods.If the fluidic seal of the joint between the upper portion of thetubular member 1110 and the upper portion of the tubular liner 1008 issatisfactory, then the uncured portion of the material 1160 within theexpanded tubular member 1110 is then removed in a conventional manner.The material 1160 within the annular region between the tubular member1110 and the tubular liner 1008 is then allowed to cure.

As illustrated in FIG. 10f, preferably any remaining cured material 1160within the interior of the expanded tubular member 1110 is then removedin a conventional manner using a conventional drill string. Theresulting tie-back liner of casing 1170 includes the expanded tubularmember 1110 and an outer annular layer 1175 of cured material 1160.

As illustrated in FIG. 10g, the remaining bottom portion of theapparatus 1100 comprising the shoe 1115 and packer 1155 is thenpreferably removed by drilling out the shoe 1115 and packer 1155 usingconventional drilling methods.

In a particularly preferred embodiment, the apparatus 1100 incorporatesthe apparatus 900.

Referring now to FIGS. 11a-11 f, an embodiment of an apparatus andmethod for hanging a tubular liner off of an existing wellbore casingwill now be described. As illustrated in FIG. 11a, a wellbore 1200 ispositioned in a subterranean formation 1205. The wellbore 1200 includesan existing cased section 1210 having a tubular casing 1215 and anannular outer layer of cement 1220.

In order to extend the wellbore 1200 into the subterranean formation1205, a drill string 1225 is used in a well known manner to drill outmaterial from the subterranean formation 1205 to form a new section1230.

As illustrated in FIG. 11b, an apparatus 1300 for forming a wellborecasing in a subterranean formation is then positioned in the new section1230 of the wellbore 100. The apparatus 1300 preferably includes anexpandable mandrel or pig 1305, a tubular member 1310, a shoe 1315, afluid passage 1320, a fluid passage 1330, a fluid passage 1335, seals1340, a support member 1345, and a wiper plug 1350.

The expandable mandrel 1305 is coupled to and supported by the supportmember 1345. The expandable mandrel 1305 is preferably adapted tocontrollably expand in a radial direction. The expandable mandrel 1305may comprise any number of conventional commercially availableexpandable mandrels modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the expandable mandrel1305 comprises a hydraulic expansion tool substantially as disclosed inU.S. Pat. No. 5,348,095, the disclosure of which is incorporated hereinby reference, modified in accordance with the teachings of the presentdisclosure.

The tubular member 1310 is coupled to and supported by the expandablemandrel 1305. The tubular member 1310 is preferably expanded in theradial direction and extruded off of the expandable mandrel 1305. Thetubular member 1310 may be fabricated from any number of materials suchas, for example, Oilfield Country Tubular Goods (OCTG), 13 chromiumsteel tubing/casing or plastic casing. In a preferred embodiment, thetubular member 1310 is fabricated from OCTG. The inner and outerdiameters of the tubular member 1310 may range, for example, fromapproximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. Ina preferred embodiment, the inner and outer diameters of the tubularmember 1310 range from about 3 to 15.5 inches and 3.5 to 16 inches,respectively in order to optimally provide minimal telescoping effect inthe most commonly encountered wellbore sizes.

In a preferred embodiment, the tubular member 1310 includes an upperportion 1355, an intermediate portion 1360, and a lower portion 1365. Ina preferred embodiment, the wall thickness and outer diameter of theupper portion 1355 of the tubular member 1310 range from about ⅜ to 1½inches and 3½ to 16 inches, respectively. In a preferred embodiment, thewall thickness and outer diameter of the intermediate portion 1360 ofthe tubular member 1310 range from about 0.625 to 0.75 inches and 3 to19 inches, respectively. In a preferred embodiment, the wall thicknessand outer diameter of the lower portion 1365 of the tubular member 1310range from about ⅜ to 1.5 inches and 3.5 to 16 inches, respectively.

In a particularly preferred embodiment, the outer diameter of the lowerportion 1365 of the tubular member 1310 is significantly less than theouter diameters of the upper and intermediate portions, 1355 and 1360,of the tubular member 1310 in order to optimize the formation of aconcentric and overlapping arrangement of wellbore casings. In thismanner, as will be described below with reference to FIGS. 12 and 13, awellhead system is optimally provided. In a preferred embodiment, theformation of a wellhead system does not include the use of a hardenablefluidic material.

In a particularly preferred embodiment, the wall thickness of theintermediate section 1360 of the tubular member 1310 is less than orequal to the wall thickness of the upper and lower sections, 1355 and1365, of the tubular member 1310 in order to optimally facilitate theinitiation of the extrusion process and optimally permit the placementof the apparatus in areas of the wellbore having tight clearances.

The tubular member 1310 preferably comprises a solid member. In apreferred embodiment, the upper end portion 1355 of the tubular member1310 is slotted, perforated, or otherwise modified to catch or slow downthe mandrel 1305 when it completes the extrusion of tubular member 1310.In a preferred embodiment, the length of the tubular member 1310 islimited to minimize the possibility of buckling. For typical tubularmember 1310 materials, the length of the tubular member 1310 ispreferably limited to between about 40 to 20,000 feet in length.

The shoe 1315 is coupled to the tubular member 1310. The shoe 1315preferably includes fluid passages 1330 and 1335. The shoe 1315 maycomprise any number of conventional commercially available shoes suchas, for example, Super Seal II float shoe, Super Seal II Down-Jet floatshoe or guide shoe with a sealing sleeve for a latch-down plug modifiedin accordance with the teachings of the present disclosure. In apreferred embodiment, the shoe 1315 comprises an aluminum down-jet guideshoe with a sealing sleeve for a latch-down plug available fromHalliburton Energy Services in Dallas, Tex., modified in accordance withthe teachings of the present disclosure, in order to optimally guide thetubular member 1310 into the wellbore 1200, optimally fluidicly isolatethe interior of the tubular member 1310, and optimally permit thecomplete drill out of the shoe 1315 upon the completion of the extrusionand cementing operations.

In a preferred embodiment, the shoe 1315 further includes one or moreside outlet ports in fluidic communication with the fluid passage 1330.In this manner, the shoe 1315 preferably injects hardenable fluidicsealing material into the region outside the shoe 1315 and tubularmember 1310. In a preferred embodiment, the shoe 1315 includes the fluidpassage 1330 having an inlet geometry that can receive a fluidic sealingmember. In this manner, the fluid passage 1330 can be sealed off byintroducing a plug, dart and/or ball sealing elements into the fluidpassage 1330.

The fluid passage 1320 permits fluidic materials to be transported toand from the interior region of the tubular member 1310 below theexpandable mandrel 1305. The fluid passage 1320 is coupled to andpositioned within the support member 1345 and the expandable mandrel1305. The fluid passage 1320 preferably extends from a position adjacentto the surface to the bottom of the expandable mandrel 1305. The fluidpassage 1320 is preferably positioned along a centerline of theapparatus 1300. The fluid passage 1320 is preferably selected totransport materials such as cement, drilling mud, or epoxies at flowrates and pressures ranging from about 0 to 3,000 gallons/minute and 0to 9,000 psi in order to optimally provide sufficient operatingpressures to circulate fluids at operationally efficient rates.

The fluid passage 1330 permits fluidic materials to be transported toand from the region exterior to the tubular member 1310 and shoe 1315.The fluid passage 1330 is coupled to and positioned within the shoe 1315in fluidic communication with the interior region 1370 of the tubularmember 1310 below the expandable mandrel 1305. The fluid passage 1330preferably has a cross-sectional shape that permits a plug, or othersimilar device, to be placed in fluid passage 1330 to thereby blockfurther passage of fluidic materials. In this manner, the interiorregion 1370 of the tubular member 1310 below the expandable mandrel 1305can be fluidicly isolated from the region exterior to the tubular member1310. This permits the interior region 1370 of the tubular member 1310below the expandable mandrel 1305 to be pressurized. The fluid passage1330 is preferably positioned substantially along the centerline of theapparatus 1300.

The fluid passage 1330 is preferably selected to convey materials suchas cement, drilling mud or epoxies at flow rates and pressures rangingfrom about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order tooptimally fill the annular region between the tubular member 1310 andthe new section 1230 of the wellbore 1200 with fluidic materials. In apreferred embodiment, the fluid passage 1330 includes an inlet geometrythat can receive a dart and/or a ball sealing member. In this manner,the fluid passage 1330 can be sealed off by introducing a plug, dartand/or ball sealing elements into the fluid passage 1320.

The fluid passage 1335 permits fluidic materials to be transported toand from the region exterior to the tubular member 1310 and shoe 1315.The fluid passage 1335 is coupled to and positioned within the shoe 1315in fluidic communication with the fluid passage 1330. The fluid passage1335 is preferably positioned substantially along the centerline of theapparatus 1300. The fluid passage 1335 is preferably selected to conveymaterials such as cement, drilling mud or epoxies at flow rates andpressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000psi in order to optimally fill the annular region between the tubularmember 1310 and the new section 1230 of the wellbore 1200 with fluidicmaterials.

The seals 1340 are coupled to and supported by the upper end portion1355 of the tubular member 1310. The seals 1340 are further positionedon an outer surface of the upper end portion 1355 of the tubular member1310. The seals 1340 permit the overlapping joint between the lower endportion of the casing 1215 and the upper portion 1355 of the tubularmember 1310 to be fluidicly sealed. The seals 1340 may comprise anynumber of conventional commercially available seals such as, forexample, lead, rubber, Teflon, or epoxy seals modified in accordancewith the teachings of the present disclosure. In a preferred embodiment,the seals 1340 comprise seals molded from Stratalock epoxy availablefrom Halliburton Energy Services in Dallas, Tex. in order to optimallyprovide a hydraulic seal in the annulus of the overlapping joint whilealso creating optimal load bearing capability to withstand typicaltensile and compressive loads.

In a preferred embodiment, the seals 1340 are selected to optimallyprovide a sufficient frictional force to support the expanded tubularmember 1310 from the existing casing 1215. In a preferred embodiment,the frictional force provided by the seals 1340 ranges from about 1,000to 1,000,000 lbf in order to optimally support the expanded tubularmember 1310.

The support member 1345 is coupled to the expandable mandrel 1305,tubular member 1310, shoe 1315, and seals 1340. The support member 1345preferably comprises an annular member having sufficient strength tocarry the apparatus 1300 into the new section 1230 of the wellbore 1200.In a preferred embodiment, the support member 1345 further includes oneor more conventional centralizers (not illustrated) to help stabilizethe tubular member 1310.

In a preferred embodiment, the support member 1345 is thoroughly cleanedprior to assembly to the remaining portions of the apparatus 1300. Inthis manner, the introduction of foreign material into the apparatus1300 is minimized. This minimizes the possibility of foreign materialclogging the various flow passages and valves of the apparatus 1300 andto ensure that no foreign material interferes with the expansionprocess.

The wiper plug 1350 is coupled to the mandrel 1305 within the interiorregion 1370 of the tubular member 1310. The wiper plug 1350 includes afluid passage 1375 that is coupled to the fluid passage 1320. The wiperplug 1350 may comprise one or more conventional commercially availablewiper plugs such as, for example, Multiple Stage Cementer latch-downplugs, Omega latch-down plugs or three-wiper latch-down plug modified inaccordance with the teachings of the present disclosure. In a preferredembodiment, the wiper plug 1350 comprises a Multiple Stage Cementerlatch-down plug available from Halliburton Energy Services in Dallas,Tex. modified in a conventional manner for releasable attachment to theexpansion mandrel 1305.

In a preferred embodiment, before or after positioning the apparatus1300 within the new section 1230 of the wellbore 1200, a couple ofwellbore volumes are circulated in order to ensure that no foreignmaterials are located within the wellbore 1200 that might clog up thevarious flow passages and valves of the apparatus 1300 and to ensurethat no foreign material interferes with the extrusion process.

As illustrated in FIG. 11c, a hardenable fluidic sealing material 1380is then pumped from a surface location into the fluid passage 1320. Thematerial 1380 then passes from the fluid passage 1320, through the fluidpassage 1375, and into the interior region 1370 of the tubular member1310 below the expandable mandrel 1305. The material 1380 then passesfrom the interior region 1370 into the fluid passage 1330. The material1380 then exits the apparatus 1300 via the fluid passage 1335 and fillsthe annular region 1390 between the exterior of the tubular member 1310and the interior wall of the new section 1230 of the wellbore 1200.Continued pumping of the material 1380 causes the material 1380 to fillup at least a portion of the annular region 1390.

The material 1380 may be pumped into the annular region 1390 atpressures and flow rates ranging, for example, from about 0 to 5000 psiand 0 to 1,500 gallons/min, respectively. In a preferred embodiment, thematerial 1380 is pumped into the annular region 1390 at pressures andflow rates ranging from about 0 to 5000 psi and 0 to 1,500 gallons/min,respectively, in order to optimally fill the annular region between thetubular member 1310 and the new section 1230 of the wellbore 1200 withthe hardenable fluidic sealing material 1380.

The hardenable fluidic sealing material 1380 may comprise any number ofconventional commercially available hardenable fluidic sealing materialssuch as, for example, slag mix, cement or epoxy. In a preferredembodiment, the hardenable fluidic sealing material 1380 comprisesblended cements designed specifically for the well section being drilledand available from Halliburton Energy Services in order to optimallyprovide support for the tubular member 1310 during displacement of thematerial 1380 in the annular region 1390. The optimum blend of thecement is preferably determined using conventional empirical methods.

The annular region 1390 preferably is filled with the material 1380 insufficient quantities to ensure that, upon radial expansion of thetubular member 1310, the annular region 1390 of the new section 1230 ofthe wellbore 1200 will be filled with material 1380.

As illustrated in FIG. 11d, once the annular region 1390 has beenadequately filled with material 1380, a wiper dart 1395, or othersimilar device, is introduced into the fluid passage 1320. The wiperdart 1395 is preferably pumped through the fluid passage 1320 by a nonhardenable fluidic material 1381. The wiper dart 1395 then preferablyengages the wiper plug 1350.

As illustrated in FIG. 11e, in a preferred embodiment, engagement of thewiper dart 1395 with the wiper plug 1350 causes the wiper plug 1350 todecouple from the mandrel 1305. The wiper dart 1395 and wiper plug 1350then preferably will lodge in the fluid passage 1330, thereby blockingfluid flow through the fluid passage 1330, and fluidicly isolating theinterior region 1370 of the tubular member 1310 from the annular region1390. In a preferred embodiment, the non hardenable fluidic material1381 is then pumped into the interior region 1370 causing the interiorregion 1370 to pressurize. Once the interior region 1370 becomessufficiently pressurized, the tubular member 1310 is extruded off of theexpandable mandrel 1305. During the extrusion process, the expandablemandrel 1305 is raised out of the expanded portion of the tubular member1310 by the support member 1345.

The wiper dart 1395 is preferably placed into the fluid passage 1320 byintroducing the wiper dart 1395 into the fluid passage 1320 at a surfacelocation in a conventional manner. The wiper dart 1395 may comprise anynumber of conventional commercially available devices from plugging afluid passage such as, for example, Multiple Stage Cementer latch-downplugs, Omega latch-down plugs or three wiper latch-down plug/dartmodified in accordance with the teachings of the present disclosure. Ina preferred embodiment, the wiper dart 1395 comprises a three wiperlatch-down plug modified to latch and seal in the Multiple StageCementer latch down plug 1350. The three wiper latch-down plug isavailable from Halliburton Energy Services in Dallas, Tex.

After blocking the fluid passage 1330 using the wiper plug 1330 andwiper dart 1395, the non hardenable fluidic material 1381 may be pumpedinto the interior region 1370 at pressures and flow rates ranging, forexample, from approximately 0 to 5000 psi and 0 to 1,500 gallons/min inorder to optimally extrude the tubular member 1310 off of the mandrel1305. In this manner, the amount of hardenable fluidic material withinthe interior of the tubular member 1310 is minimized.

In a preferred embodiment, after blocking the fluid passage 1330, thenon hardenable fluidic material 1381 is preferably pumped into theinterior region 1370 at pressures and flow rates ranging fromapproximately 500 to 9,000 psi and 40 to 3,000 gallons/min in order tooptimally provide operating pressures to maintain the expansion processat rates sufficient to permit adjustments to be made in operatingparameters during the extrusion process.

For typical tubular members 1310, the extrusion of the tubular member1310 off of the expandable mandrel 1305 will begin when the pressure ofthe interior region 1370 reaches, for example, approximately 500 to9,000 psi. In a preferred embodiment, the extrusion of the tubularmember 1310 off of the expandable mandrel 1305 is a function of thetubular member diameter, wall thickness of the tubular member, geometryof the mandrel, the type of lubricant, the composition of the shoe andtubular member, and the yield strength of the tubular member. Theoptimum flow rate and operating pressures are preferably determinedusing conventional empirical methods.

During the extrusion process, the expandable mandrel 1305 may be raisedout of the expanded portion of the tubular member 1310 at rates ranging,for example, from about 0 to 5 ft/sec. In a preferred embodiment, duringthe extrusion process, the expandable mandrel 1305 may be raised out ofthe expanded portion of the tubular member 1310 at rates ranging fromabout 0 to 2 ft/sec in order to optimally provide an efficient process,optimally permit operator adjustment of operation parameters, and ensureoptimal completion of the extrusion process before curing of thematerial 1380.

When the upper end portion 1355 of the tubular member 1310 is extrudedoff of the expandable mandrel 1305, the outer surface of the upper endportion 1355 of the tubular member 1310 will preferably contact theinterior surface of the lower end portion of the casing 1215 to form anfluid tight overlapping joint. The contact pressure of the overlappingjoint may range, for example, from approximately 50 to 20,000 psi. In apreferred embodiment, the contact pressure of the overlapping jointranges from approximately 400 to 10,000 psi in order to optimallyprovide contact pressure sufficient to ensure annular sealing andprovide enough resistance to withstand typical tensile and compressiveloads. In a particularly preferred embodiment, the sealing members 1340will ensure an adequate fluidic and gaseous seal in the overlappingjoint.

In a preferred embodiment, the operating pressure and flow rate of thenon hardenable fluidic material 1381 is controllably ramped down whenthe expandable mandrel 1305 reaches the upper end portion 1355 of thetubular member 1310. In this manner, the sudden release of pressurecaused by the complete extrusion of the tubular member 1310 off of theexpandable mandrel 1305 can be minimized. In a preferred embodiment, theoperating pressure is reduced in a substantially linear fashion from100% to about 10% during the end of the extrusion process beginning whenthe mandrel 1305 has completed approximately all but about 5 feet of theextrusion process.

Alternatively, or in combination, a shock absorber is provided in thesupport member 1345 in order to absorb the shock caused by the suddenrelease of pressure.

Alternatively, or in combination, a mandrel catching structure isprovided in the upper end portion 1355 of the tubular member 1310 inorder to catch or at least decelerate the mandrel 1305.

Once the extrusion process is completed, the expandable mandrel 1305 isremoved from the wellbore 1200. In a preferred embodiment, either beforeor after the removal of the expandable mandrel 1305, the integrity ofthe fluidic seal of the overlapping joint between the upper portion 1355of the tubular member 1310 and the lower portion of the casing 1215 istested using conventional methods. If the fluidic seal of theoverlapping joint between the upper portion 1355 of the tubular member1310 and the lower portion of the casing 1215 is satisfactory, then theuncured portion of the material 1380 within the expanded tubular member1310 is then removed in a conventional manner. The material 1380 withinthe annular region 1390 is then allowed to cure.

As illustrated in FIG. 11f, preferably any remaining cured material 1380within the interior of the expanded tubular member 1310 is then removedin a conventional manner using a conventional drill string. Theresulting new section of casing 1400 includes the expanded tubularmember 1310 and an outer annular layer 1405 of cured material 305. Thebottom portion of the apparatus 1300 comprising the shoe 1315 may thenbe removed by drilling out the shoe 1315 using conventional drillingmethods.

Referring now to FIGS. 12 and 13, a preferred embodiment of a wellheadsystem 1500 formed using one or more of the apparatus and processesdescribed above with reference to FIGS. 1-11f will be described. Thewellhead system 1500 preferably includes a conventional Christmastree/drilling spool assembly 1505, a thick wall casing 1510, an annularbody of cement 1515, an outer casing 1520, an annular body of cement1525, an intermediate casing 1530, and an inner casing 1535.

The Christmas tree/drilling spool assembly 1505 may comprise any numberof conventional Christmas tree/drilling spool assemblies such as, forexample, the SS-15 Subsea Wellhead System, Spool Tree Subsea ProductionSystem or the Compact Wellhead System available from suppliers such asDril-Quip, Cameron or Breda, modified in accordance with the teachingsof the present disclosure. The drilling spool assembly 1505 ispreferably operably coupled to the thick wall casing 1510 and/or theouter casing 1520. The assembly 1505 may be coupled to the thick wallcasing 1510 and/or outer casing 1520, for example, by welding, athreaded connection or made from single stock. In a preferredembodiment, the assembly 1505 is coupled to the thick wall casing 1510and/or outer casing 1520 by welding.

The thick wall casing 1510 is positioned in the upper end of a wellbore1540. In a preferred embodiment, at least a portion of the thick wallcasing 1510 extends above the surface 1545 in order to optimally provideeasy access and attachment to the Christmas tree/drilling spool assembly1505. The thick wall casing 1510 is preferably coupled to the Christmastree/drilling spool assembly 1505, the annular body of cement 1515, andthe outer casing 1520.

The thick wall casing 1510 may comprise any number of conventionalcommercially available high strength wellbore casings such as, forexample, Oilfield Country Tubular Goods, titanium tubing or stainlesssteel tubing. In a preferred embodiment, the thick wall casing 1510comprises Oilfield Country Tubular Goods available from various foreignand domestic steel mills. In a preferred embodiment, the thick wallcasing 1510 has a yield strength of about 400,000 to 135,000 psi inorder to optimally provide maximum burst, collapse, and tensilestrengths. In a preferred embodiment, the thick wall casing 1510 has afailure strength in excess of about 5,000 to 20,000 psi in order tooptimally provide maximum operating capacity and resistance todegradation of capacity after being drilled through for an extended timeperiod.

The annular body of cement 1515 provides support for the thick wallcasing 1510. The annular body of cement 1515 may be provided using anynumber of conventional processes for forming an annular body of cementin a wellbore. The annular body of cement 1515 may comprise any numberof conventional cement mixtures.

The outer casing 1520 is coupled to the thick wall casing 1510. Theouter casing 1520 may be fabricated from any number of conventionalcommercially available tubular members modified in accordance with theteachings of the present disclosure. In a preferred embodiment, theouter casing 1520 comprises any one of the expandable tubular membersdescribed above with reference to FIGS. 1-11f.

In a preferred embodiment, the outer casing 1520 is coupled to the thickwall casing 1510 by expanding the outer casing 1520 into contact with atleast a portion of the interior surface of the thick wall casing 1510using any one of the embodiments of the processes and apparatusdescribed above with reference to FIGS. 1-11f. In an alternativeembodiment, substantially all of the overlap of the outer casing 1520with the thick wall casing 1510 contacts with the interior surface ofthe thick wall casing 1510.

The contact pressure of the interface between the outer casing 1520 andthe thick wall casing 1510 may range, for example, from about 500 to10,000 psi. In a preferred embodiment, the contact pressure between theouter casing 1520 and the thick wall casing 1510 ranges from about 500to 10,000 psi in order to optimally activate the pressure activatedsealing members and to ensure that the overlapping joint will optimallywithstand typical extremes of tensile and compressive loads that areexperienced during drilling and production operations.

As illustrated in FIG. 13, in a particularly preferred embodiment, theupper end of the outer casing 1520 includes one or more sealing members1550 that provide a gaseous and fluidic seal between the expanded outercasing 1520 and the interior wall of the thick wall casing 1510. Thesealing members 1550 may comprise any number of conventionalcommercially available seals such as, for example, lead, plastic,rubber, Teflon or epoxy, modified in accordance with the teachings ofthe present disclosure. In a preferred embodiment, the sealing members1550 comprise seals molded from StrataLock epoxy available fromHalliburton Energy Services in order to optimally provide an hydraulicseal and a load bearing interference fit between the tubular members. Ina preferred embodiment, the contact pressure of the interface betweenthe thick wall casing 1510 and the outer casing 1520 ranges from about500 to 10,000 psi in order to optimally activate the sealing members1550 and also optimally ensure that the joint will withstand the typicaloperating extremes of tensile and compressive loads during drilling andproduction operations.

In an alternative preferred embodiment, the outer casing 1520 and thethick walled casing 1510 are combined in one unitary member.

The annular body of cement 1525 provides support for the outer casing1520. In a preferred embodiment, the annular body of cement 1525 isprovided using any one of the embodiments of the apparatus and processesdescribed above with reference to FIGS. 1-11f.

The intermediate casing 1530 may be coupled to the outer casing 1520 orthe thick wall casing 1510. In a preferred embodiment, the intermediatecasing 1530 is coupled to the thick wall casing 1510. The intermediatecasing 1530 may be fabricated from any number of conventionalcommercially available tubular members modified in accordance with theteachings of the present disclosure. In a preferred embodiment, theintermediate casing 1530 comprises any one of the expandable tubularmembers described above with reference to FIGS. 1-11f.

In a preferred embodiment, the intermediate casing 1530 is coupled tothe thick wall casing 1510 by expanding at least a portion of theintermediate casing 1530 into contact with the interior surface of thethick wall casing 1510 using any one of the processes and apparatusdescribed above with reference to FIGS. 1-11f. In an alternativepreferred embodiment, the entire length of the overlap of theintermediate casing 1530 with the thick wall casing 1510 contacts theinner surface of the thick wall casing 1510. The contact pressure of theinterface between the intermediate casing 1530 and the thick wall casing1510 may range, for example from about 500 to 10,000 psi. In a preferredembodiment, the contact pressure between the intermediate casing 1530and the thick wall casing 1510 ranges from about 500 to 10,000 psi inorder to optimally activate the pressure activated sealing members andto optimally ensure that the joint will withstand typical operatingextremes of tensile and compressive loads experienced during drillingand production operations.

As illustrated in FIG. 13, in a particularly preferred embodiment, theupper end of the intermediate casing 1530 includes one or more sealingmembers 1560 that provide a gaseous and fluidic seal between theexpanded end of the intermediate casing 1530 and the interior wall ofthe thick wall casing 1510. The sealing members 1560 may comprise anynumber of conventional commercially available seals such as, forexample, plastic, lead, rubber, Teflon or epoxy, modified in accordancewith the teachings of the present disclosure. In a preferred embodiment,the sealing members 1560 comprise seals molded from StrataLock epoxyavailable from Halliburton Energy Services in order to optimally providea hydraulic seal and a load bearing interference fit between the tubularmembers.

In a preferred embodiment, the contact pressure of the interface betweenthe expanded end of the intermediate casing 1530 and the thick wallcasing 1510 ranges from about 500 to 10,000 psi in order to optimallyactivate the sealing members 1560 and also optimally ensure that thejoint will withstand typical operating extremes of tensile andcompressive loads that are experienced during drilling and productionoperations.

The inner casing 1535 may be coupled to the outer casing 1520 or thethick wall casing 1510. In a preferred embodiment, the inner casing 1535is coupled to the thick wall casing 1510. The inner casing 1535 may befabricated from any number of conventional commercially availabletubular members modified in accordance with the teachings of the presentdisclosure. In a preferred embodiment, the inner casing 1535 comprisesany one of the expandable tubular members described above with referenceto FIGS. 1-11f.

In a preferred embodiment, the inner casing 1535 is coupled to the outercasing 1520 by expanding at least a portion of the inner casing 1535into contact with the interior surface of the thick wall casing 1510using any one of the processes and apparatus described above withreference to FIGS. 1-11f. In an alternative preferred embodiment, theentire length of the overlap of the inner casing 1535 with the thickwall casing 1510 and intermediate casing 1530 contacts the innersurfaces of the thick wall casing 1510 and intermediate casing 1530. Thecontact pressure of the interface between the inner casing 1535 and thethick wall casing 1510 may range, for example from about 500 to 10,000psi. In a preferred embodiment, the contact pressure between the innercasing 1535 and the thick wall casing 1510 ranges from about 500 to10,000 psi in order to optimally activate the pressure activated sealingmembers and to ensure that the joint will withstand typical extremes oftensile and compressive loads that are commonly experienced duringdrilling and production operations.

As illustrated in FIG. 13, in a particularly preferred embodiment, theupper end of the inner casing 1535 includes one or more sealing members1570 that provide a gaseous and fluidic seal between the expanded end ofthe inner casing 1535 and the interior wall of the thick wall casing1510. The sealing members 1570 may comprise any number of conventionalcommercially available seals such as, for example, lead, plastic,rubber, Teflon or epoxy, modified in accordance with the teachings ofthe present disclosure. In a preferred embodiment, the sealing members1570 comprise seals molded from StrataLock epoxy available fromHalliburton Energy Services in order to optimally provide an hydraulicseal and a load bearing interference fit. In a preferred embodiment, thecontact pressure of the interface between the expanded end of the innercasing 1535 and the thick wall casing 1510 ranges from about 500 to10,000 psi in order to optimally activate the sealing members 1570 andalso to optimally ensure that the joint will withstand typical operatingextremes of tensile and compressive loads that are experienced duringdrilling and production operations.

In an alternative embodiment, the inner casings, 1520, 1530 and 1535,may be coupled to a previously positioned tubular member that is in turncoupled to the outer casing 1510. More generally, the present preferredembodiments may be used to form a concentric arrangement of tubularmembers.

Referring now to FIGS. 14a, 14 b, 14 c, 14 d, 14 e and 14 f, a preferredembodiment of a method and apparatus for forming a mono-diameter wellcasing within a subterranean formation will now be described.

As illustrated in FIG. 14a, a wellbore 1600 is positioned in asubterranean formation 1605. A first section of casing 1610 is formed inthe wellbore 1600. The first section of casing 1610 includes an annularouter body of cement 1615 and a tubular section of casing 1620. Thefirst section of casing 1610 may be formed in the wellbore 1600 usingconventional methods and apparatus. In a preferred embodiment, the firstsection of casing 1610 is formed using one or more of the methods andapparatus described above with reference to FIGS. 1-13 or below withreference to FIGS. 14b-17 b.

The annular body of cement 1615 may comprise any number of conventionalcommercially available cement, or other load bearing, compositions.Alternatively, the body of cement 1615 may be omitted or replaced withan epoxy mixture.

The tubular section of casing 1620 preferably includes an upper end 1625and a lower end 1630. Preferably, the lower end 1625 of the tubularsection of casing 1620 includes an outer annular recess 1635 extendingfrom the lower end 1630 of the tubular section of casing 1620. In thismanner, the lower end 1625 of the tubular section of casing 1620includes a thin walled section 1640. In a preferred embodiment, anannular body 1645 of a compressible material is coupled to and at leastpartially positioned within the outer annular recess 1635. In thismanner, the body of compressible material 1645 surrounds at least aportion of the thin walled section 1640.

The tubular section of casing 1620 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, stainless steel, automotive grade steel,carbon steel, low alloy steel, fiberglass or plastics. In a preferredembodiment, the tubular section of casing 1620 is fabricated fromoilfield country tubular goods available from various foreign anddomestic steel mills. The wall thickness of the thin walled section 1640may range from about 0.125 to 1.5 inches. In a preferred embodiment, thewall thickness of the thin walled section 1640 ranges from 0.25 to 1.0inches in order to optimally provide burst strength for typicaloperational conditions while also minimizing resistance to radialexpansion. The axial length of the thin walled section 1640 may rangefrom about 120 to 2400 inches. In a preferred embodiment, the axiallength of the thin walled section 1640 ranges from about 240 to 480inches.

The annular body of compressible material 1645 helps to minimize theradial force required to expand the tubular casing 1620 in the overlapwith the tubular member 1715, helps to create a fluidic seal in theoverlap with the tubular member 1715, and helps to create aninterference fit sufficient to permit the tubular member 1715 to besupported by the tubular casing 1620. The annular body of compressiblematerial 1645 may comprise any number of commercially availablecompressible materials such as, for example, epoxy, rubber, Teflon,plastics or lead tubes. In a preferred embodiment, the annular body ofcompressible material 1645 comprises StrataLock epoxy available fromHalliburton Energy Services in order to optimally provide an hydraulicseal in the overlapped joint while also having compliance to therebyminimize the radial force required to expand the tubular casing. Thewall thickness of the annular body of compressible material 1645 mayrange from about 0.05 to 0.75 inches. In a preferred embodiment, thewall thickness of the annular body of compressible material 1645 rangesfrom about 0.1 to 0.5 inches in order to optimally provide a largecompressible zone, minimize the radial forces required to expand thetubular casing, provide thickness for casing strings to provide contactwith the inner surface of the wellbore upon radial expansion, andprovide an hydraulic seal.

As illustrated in FIG. 14b, in order to extend the wellbore 1600 intothe subterranean formation 1605, a drill string is used in a well knownmanner to drill out material from the subterranean formation 1605 toform a new wellbore section 1650. The diameter of the new section 1650is preferably equal to or greater than the inner diameter of the tubularsection of casing 1620.

As illustrated in FIG. 14c, a preferred embodiment of an apparatus 1700for forming a mono-diameter wellbore casing in a subterranean formationis then positioned in the new section 1650 of the wellbore 1600. Theapparatus 1700 preferably includes a support member 1705, an expandablemandrel or pig 1710, a tubular member 1715, a shoe 1720, slips 1725, afluid passage 1730, one or more fluid passages 1735, a fluid passage1740, a first compressible annular body 1745, a second compressibleannular body 1750, and a pressure chamber 1755.

The support member 1705 supports the apparatus 1700 within the wellbore1600. The support member 1705 is coupled to the mandrel 1710, thetubular member 1715, the shoe 1720, and the slips 1725. The supportmember 1075 preferably comprises a substantially hollow tubular member.The fluid passage 1730 is positioned within the support member 1705. Thefluid passages 1735 fluidicly couple the fluid passage 1730 with thepressure chamber 1755. The fluid passage 1740 fluidicly couples thefluid passage 1730 with the region outside of the apparatus 1700.

The support member 1705 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, stainless steel, low alloy steel, carbonsteel, 13 chromium steel, fiberglass, or other high strength materials.In a preferred embodiment, the support member 1705 is fabricated fromoilfield country tubular goods available from various foreign anddomestic steel mills in order to optimally provide operational strengthand facilitate the use of other standard oil exploration handlingequipment. In a preferred embodiment, at least a portion of the supportmember 1705 comprises coiled tubing or a drill pipe. In a particularlypreferred embodiment, the support member 1705 includes a load shoulder1820 for supporting the mandrel 1710 when the pressure chamber 1755 isunpressurized.

The mandrel 1710 is supported by and slidingly coupled to the supportmember 1705 and the shoe 1720. The mandrel 1710 preferably includes anupper portion 1760 and a lower portion 1765. Preferably, the upperportion 1760 of the mandrel 1710 and the support member 1705 togetherdefine the pressure chamber 1755. Preferably, the lower portion 1765 ofthe mandrel 1710 includes an expansion member 1770 for radiallyexpanding the tubular member 1715.

In a preferred embodiment, the upper portion 1760 of the mandrel 1710includes a tubular member 1775 having an inner diameter greater than anouter diameter of the support member 1705. In this manner, an annularpressure chamber 1755 is defined by and positioned between the tubularmember 1775 and the support member 1705. The top 1780 of the tubularmember 1775 preferably includes a bearing and a seal for sealing andsupporting the top 1780 of the tubular member 1775 against the outersurface of the support member 1705. The bottom 1785 of the tubularmember 1775 preferably includes a bearing and seal for sealing andsupporting the bottom 1785 of the tubular member 1775 against the outersurface of the support member 1705 or shoe 1720. In this manner, themandrel 1710 moves in an axial direction upon the pressurization of thepressure chamber 1755.

The lower portion 1765 of the mandrel 1710 preferably includes anexpansion member 1770 for radially expanding the tubular member 1715during the pressurization of the pressure chamber 1755. In a preferredembodiment, the expansion member is expandible in the radial direction.In a preferred embodiment, the inner surface of the lower portion 1765of the mandrel 1710 mates with and slides with respect to the outersurface of the shoe 1720. The outer diameter of the expansion member1770 may range from about 90 to 100% of the inner diameter of thetubular casing 1620. In a preferred embodiment, the outer diameter ofthe expansion member 1770 ranges from about 95 to 99% of the innerdiameter of the tubular casing 1620. The expansion member 1770 may befabricated from any number of conventional commercially availablematerials such as, for example, machine tool steel, ceramics, tungstencarbide, titanium or other high strength alloys.

In a preferred embodiment, the expansion member 1770 is fabricated fromD2 machine tool steel in order to optimally provide high strength andabrasion resistance.

The tubular member 1715 is coupled to and supported by the supportmember 1705 and slips 1725. The tubular member 1715 includes an upperportion 1790 and a lower portion 1795.

The upper portion 1790 of the tubular member 1715 preferably includes aninner annular recess 1800 that extends from the upper portion 1790 ofthe tubular member 1715. In this manner, at least a portion of the upperportion 1790 of the tubular member 1715 includes a thin walled section1805. The first compressible annular member 1745 is preferably coupledto and supported by the outer surface of the upper portion 1790 of thetubular member 1715 in opposing relation to the thin wall section 1805.

The lower portion 1795 of the tubular member 1715 preferably includes anouter annular recess 1810 that extends from the lower portion 1790 ofthe tubular member 1715. In this manner, at least a portion of the lowerportion 1795 of the tubular member 1715 includes a thin walled section1815. The second compressible annular member 1750 is coupled to and atleast partially supported within the outer annular recess 1810 of theupper portion 1790 of the tubular member 1715 in opposing relation tothe thin wall section 1815.

The tubular member 1715 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, stainless steel, low alloy steel, carbonsteel, automotive grade steel, fiberglass, 13 chrome steel, other highstrength material, or high strength plastics. In a preferred embodiment,the tubular member 1715 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide operational strength.

The shoe 1720 is supported by and coupled to the support member 1705.The shoe 1720 preferably comprises a substantially hollow tubularmember. In a preferred embodiment, the wall thickness of the shoe 1720is greater than the wall thickness of the support member 1705 in orderto optimally provide increased radial support to the mandrel 1710. Theshoe 1720 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, stainless steel, automotive grade steel, low alloy steel, carbonsteel, or high strength plastics. In a preferred embodiment, the shoe1720 is fabricated from oilfield country tubular goods available fromvarious foreign and domestic steel mills in order to optimally providematching operational strength throughout the apparatus.

The slips 1725 are coupled to and supported by the support member 1705.The slips 1725 removably support the tubular member 1715. In thismanner, during the radial expansion of the tubular member 1715, theslips 1725 help to maintain the tubular member 1715 in a substantiallystationary position by preventing upward movement of the tubular member1715.

The slips 1725 may comprise any number of conventional commerciallyavailable slips such as, for example, RTTS packer tungsten carbidemechanical slips, RTTS packer wicker type mechanical slips, or Model 3Lretrievable bridge plug tungsten carbide upper mechanical slips. In apreferred embodiment, the slips 1725 comprise RTTS packer tungstencarbide mechanical slips available from Halliburton Energy Services. Ina preferred embodiment, the slips 1725 are adapted to support axialforces ranging from about 0 to 750,000 lbf.

The fluid passage 1730 conveys fluidic materials from a surface locationinto the interior of the support member 1705, the pressure chamber 1755,and the region exterior of the apparatus 1700. The fluid passage 1730 isfludicly coupled to the pressure chamber 1755 by the fluid passages1735. The fluid passage 1730 is fluidicly coupled to the region exteriorto the apparatus 1700 by the fluid passage 1740.

In a preferred embodiment, the fluid passage 1730 is adapted to conveyfluidic materials such as, for example, cement, epoxy, drilling muds,slag mix, water or drilling gasses. In a preferred embodiment, the fluidpassage 1730 is adapted to convey fluidic materials at flow rate andpressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000psi. in order to optimally provide flow rates and operational pressuresfor the radial expansion processes.

The fluid passages 1735 convey fluidic material from the fluid passage1730 to the pressure chamber 1755. In a preferred embodiment, the fluidpassage 1735 is adapted to convey fluidic materials such as, forexample, cement, epoxy, drilling muds, water or drilling gasses. In apreferred embodiment, the fluid passage 1735 is adapted to conveyfluidic materials at flow rate and pressures ranging from about 0 to 500gallons/minute and 0 to 9,000 psi. in order to optimally provideoperating pressures and flow rates for the various expansion processes.

The fluid passage 1740 conveys fluidic materials from the fluid passage1730 to the region exterior to the apparatus 1700. In a preferredembodiment, the fluid passage 1740 is adapted to convey fluidicmaterials such as, for example, cement, epoxy, drilling muds, water ordrilling gasses. In a preferred embodiment, the fluid passage 1740 isadapted to convey fluidic materials at flow rate and pressures rangingfrom about 0 to 3,000 gallons/minute and 0 to 9,000 psi. in order tooptimally provide operating pressures and flow rates for the variousradial expansion processes.

In a preferred embodiment, the fluid passage 1740 is adapted to receivea plug or other similar device for sealing the fluid passage 1740. Inthis manner, the pressure chamber 1755 may be pressurized.

The first compressible annular body 1745 is coupled to and supported byan exterior surface of the upper portion 1790 of the tubular member1715. In a preferred embodiment, the first compressible annular body1745 is positioned in opposing relation to the thin walled section 1805of the tubular member 1715.

The first compressible annular body 1745 helps to minimize the radialforce required to expand the tubular member 1715 in the overlap with thetubular casing 1620, helps to create a fluidic seal in the overlap withthe tubular casing 1620, and helps to create an interference fitsufficient to permit the tubular member 1715 to be supported by thetubular casing 1620. The first compressible annular body 1745 maycomprise any number of commercially available compressible materialssuch as, for example, epoxy, rubber, Teflon, plastics, or hollow leadtubes. In a preferred embodiment, the first compressible annular body1745 comprises StrataLock epoxy available from Halliburton EnergyServices in order to optimally provide an hydraulic seal, andcompressibility to minimize the radial expansion force.

The wall thickness of the first compressible annular body 1745 may rangefrom about 0.05 to 0.75 inches. In a preferred embodiment, the wallthickness of the first compressible annular body 1745 ranges from about0.1 to 0.5 inches in order to optimally (1) provide a large compressiblezone, (2) minimize the required radial expansion force, (3) transfer theradial force to the tubular casings. As a result, in a preferredembodiment, overall the outer diameter of the tubular member 1715 isapproximately equal to the overall inner diameter of the tubular member1620.

The second compressible annular body 1750 is coupled to and at leastpartially supported within the outer annular recess 1810 of the tubularmember 1715. In a preferred embodiment, the second compressible annularbody 1750 is positioned in opposing relation to the thin walled section1815 of the tubular member 1715.

The second compressible annular body 1750 helps to minimize the radialforce required to expand the tubular member 1715 in the overlap withanother tubular member, helps to create a fluidic seal in the overlap ofthe tubular member 1715 with another tubular member, and helps to createan interference fit sufficient to permit another tubular member to besupported by the tubular member 1715. The second compressible annularbody 1750 may comprise any number of commercially available compressiblematerials such as, for example, epoxy, rubber, Teflon, plastics orhollow lead tubing. In a preferred embodiment, the first compressibleannular body 1750 comprises StrataLock epoxy available from HalliburtonEnergy Services in order to optimally provide an hydraulic seal in theoverlapped joint, and compressibility that minimizes the radialexpansion force.

The wall thickness of the second compressible annular body 1750 mayrange from about 0.05 to 0.75 inches. In a preferred embodiment, thewall thickness of the second compressible annular body 1750 ranges fromabout 0.1 to 0.5 inches in order to optimally provide a largecompressible zone, and minimize the radial force required to expand thetubular member 1715 during subsequent radial expansion operations.

In an alternative embodiment, the outside diameter of the secondcompressible annular body 1750 is adapted to provide a seal against thesurrounding formation thereby eliminating the need for an outer annularbody of cement.

The pressure chamber 1755 is fludicly coupled to the fluid passage 1730by the fluid passages 1735. The pressure chamber 1755 is preferablyadapted to receive fluidic materials such as, for example, drillingmuds, water or drilling gases. In a preferred embodiment, the pressurechamber 1755 is adapted to receive fluidic materials at flow rate andpressures ranging from about 0 to 500 gallons/minute and 0 to 9,000 psi.in order to optimally provide expansion pressure. In a preferredembodiment, during pressurization of the pressure chamber 1755, theoperating pressure of the pressure chamber ranges from about 0 to 5,000psi in order to optimally provide expansion pressure while minimizingthe possibility of a catastrophic failure due to over pressurization.

As illustrated in FIG. 14d, the apparatus 1700 is preferably positionedin the wellbore 1600 with the tubular member 1715 positioned in anoverlapping relationship with the tubular casing 1620. In a particularlypreferred embodiment, the thin wall sections, 1640 and 1805, of thetubular casing 1620 and tubular member 1725 are positioned in opposingoverlapping relation. In this manner, the radial expansion of thetubular member 1725 will compress the thin wall sections, 1640 and 1805,and annular compressible members, 1645 and 1745, into intimate contact.

After positioning of the apparatus 1700, a fluidic material 1825 is thenpumped into the fluid passage 1730. The fluidic material 1825 maycomprise any number of conventional commercially available materialssuch as, for example, water, drilling mud, drilling gases, cement orepoxy. In a preferred embodiment, the fluidic material 1825 comprises ahardenable fluidic sealing material such as, for example, cement inorder to provide an outer annular body around the expanded tubularmember 1715.

The fluidic material 1825 may be pumped into the fluid passage 1730 atoperating pressures and flow rates, for example, ranging from about 0 to9,000 psi and 0 to 3,000 gallons/minute.

The fluidic material 1825 pumped into the fluid passage 1730 passesthrough the fluid passage 1740 and outside of the apparatus 1700. Thefluidic material 1825 fills the annular region 1830 between the outsideof the apparatus 1700 and the interior walls of the wellbore 1600.

As illustrated in FIG. 14e, a plug 1835 is then introduced into thefluid passage 1730. The plug 1835 lodges in the inlet to the fluidpassage 1740 fluidicly isolating and blocking off the fluid passage1730.

A fluidic material 1840 is then pumped into the fluid passage 1730. Thefluidic material 1840 may comprise any number of conventionalcommercially available materials such as, for example, water, drillingmud or drilling gases. In a preferred embodiment, the fluidic material1825 comprises a non-hardenable fluidic material such as, for example,drilling mud or drilling gases in order to optimally providepressurization of the pressure chamber 1755.

The fluidic material 1840 may be pumped into the fluid passage 1730 atoperating pressures and flow rates ranging, for example, from about 0 to9,000 psi and 0 to 500 gallons/minute. In a preferred embodiment, thefluidic material 1840 is pumped into the fluid passage 1730 at operatingpressures and flow rates ranging from about 500 to 5,000 psi and 0 to500 gallons/minute in order to optimally provide operating pressures andflow rates for radial expansion.

The fluidic material 1840 pumped into the fluid passage 1730 passesthrough the fluid passages 1735 and into the pressure chamber 1755.Continued pumping of the fluidic material 1840 pressurizes the pressurechamber 1755. The pressurization of the pressure chamber 1755 causes themandrel 1710 to move relative to the support member 1705 in thedirection indicated by the arrows 1845. In this manner, the mandrel 1710will cause the tubular member 1715 to expand in the radial direction.

During the radial expansion process, the tubular member 1715 isprevented from moving in an upward direction by the slips 1725. A lengthof the tubular member 1715 is then expanded in the radial directionthrough the pressurization of the pressure chamber 1755. The length ofthe tubular member 1715 that is expanded during the expansion processwill be proportional to the stroke length of the mandrel 1710. Upon thecompletion of a stroke, the operating pressure of the pressure chamber1755 is then reduced and the mandrel 1710 drops to it rest position withthe tubular member 1715 supported by the mandrel 1715. The position ofthe support member 1705 may be adjusted throughout the radial expansionprocess in order to maintain the overlapping relationship between thethin walled sections, 1640 and 1805, of the tubular casing 1620 andtubular member 1715. The stroking of the mandrel 1710 is then repeated,as necessary, until the thin walled section 1805 of the tubular member1715 is expanded into the thin walled section 1640 of the tubular casing1620.

In a preferred embodiment, during the final stroke of the mandrel 1710,the slips 1725 are positioned as close as possible to the thin walledsection 1805 of the tubular member 1715 in order minimize slippagebetween the tubular member 1715 and tubular casing 1620 at the end ofthe radial expansion process. Alternatively, or in addition, the outsidediameter of the first compressive annular member 1745 is selected toensure sufficient interference fit with the tubular casing 1620 toprevent axial displacement of the tubular member 1715 during the finalstroke. Alternatively, or in addition, the outside diameter of thesecond compressive annular body 1750 is large enough to provide aninterference fit with the inside walls of the wellbore 1600 at anearlier point in the radial expansion process so as to prevent furtheraxial displacement of the tubular member 1715. In this finalalternative, the interference fit is preferably selected to permitexpansion of the tubular member 1715 by pulling the mandrel 1710 out ofthe wellbore 1600, without having to pressurize the pressure chamber1755.

During the radial expansion process, the pressurized areas of theapparatus 1700 are limited to the fluid passages 1730 within the supportmember 1705 and the pressure chamber 1755 within the mandrel 1710. Nofluid pressure acts directly on the tubular member 1715. This permitsthe use of operating pressures higher than the tubular member 1715 couldnormally withstand.

Once the tubular member 1715 has been completely expanded off of themandrel 1710, the support member 1705 and mandrel 1710 are removed fromthe wellbore 1600. In a preferred embodiment, the contact pressurebetween the deformed thin wall sections, 1640 and 1805, and compressibleannular members, 1645 and 1745, ranges from about 400 to 10,000 psi inorder to optimally support the tubular member 1715 using the tubularcasing 1620.

In this manner, the tubular member 1715 is radially expanded intocontact with the tubular casing 1620 by pressurizing the interior of thefluid passage 1730 and the pressure chamber 1755.

As illustrated in FIG. 14f, in a preferred embodiment, once the tubularmember 1715 is completely expanded in the radial direction by themandrel 1710, the support member 1705 and mandrel 1710 are removed fromthe wellbore 1600. In a preferred embodiment, the annular body ofhardenable fluidic material is then allowed to cure to form a rigidouter annular body 1850. In the case where the tubular member 1715 isslotted, the hardenable fluidic material will preferably permeate andenvelop the expanded tubular member 1715.

The resulting new section of wellbore casing 1855 includes the expandedtubular member 1715 and the rigid outer annular body 1850. Theoverlapping joint 1860 between the tubular casing 1620 and the expandedtubular member 1715 includes the deformed thin wall sections, 1640 and1805, and the compressible annular bodies, 1645 and 1745. The innerdiameter of the resulting combined wellbore casings is substantiallyconstant. In this manner, a mono-diameter wellbore casing is formed.This process of expanding overlapping tubular members having thin wallend portions with compressible annular bodies into contact can berepeated for the entire length of a wellbore. In this manner, amono-diameter wellbore casing can be provided for thousands of feet in asubterranean formation.

Referring now to FIGS. 15, 15 a and 15 b, an embodiment of an apparatus1900 for expanding a tubular member will be described. The apparatus1900 preferably includes a drillpipe 1905, an innerstring adapter 1910,a sealing sleeve 1915, an inner sealing mandrel 1920, an upper sealinghead 1925, a lower sealing head 1930, an outer sealing mandrel 1935, aload mandrel 1940, an expansion cone 1945, a mandrel launcher 1950, amechanical slip body 1955, mechanical slips 1960, drag blocks 1965,casing 1970, and fluid passages 1975, 1980, 1985, and 1990.

The drillpipe 1905 is coupled to the innerstring adapter 1910. Duringoperation of the apparatus 1900, the drillpipe 1905 supports theapparatus 1900. The drillpipe 1905 preferably comprises a substantiallyhollow tubular member or members. The drillpipe 1905 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, oilfield country tubular drillpipe, fiberglass orcoiled tubing. In a preferred embodiment, the drillpipe 1905 isfabricated from coiled tubing in order to faciliate the placement of theapparatus 1900 in non-vertical wellbores. The drillpipe 1905 may becoupled to the innerstring adapter 1910 using any number of conventionalcommercially available mechanical couplings such as, for example,drillpipe connectors, OCTG specialty type box and pin connectors, aratchet-latch type connector or a standard box by pin connector. In apreferred embodiment, the drillpipe 1905 is removably coupled to theinnerstring adapter 1910 by a drillpipe connection.

The drillpipe 1905 preferably includes a fluid passage 1975 that isadapted to convey fluidic materials from a surface location into thefluid passage 1980. In a preferred embodiment, the fluid passage 1975 isadapted to convey fluidic materials such as, for example, cement,drilling mud, epoxy or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The innerstring adapter 1910 is coupled to the drill string 1905 and thesealing sleeve 1915. The innerstring adapter 1910 preferably comprises asubstantially hollow tubular member or members. The innerstring adapter1910 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oil country tubular goods, lowalloy steel, carbon steel, stainless steel or other high strengthmaterials. In a preferred embodiment, the innerstring adapter 1910 isfabricated from oilfield country tubular goods in order to optimallyprovide mechanical properties that closely match those of the drillstring 1905.

The innerstring adapter 1910 may be coupled to the drill string 1905using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connectors, oilfield countrytubular goods specialty type threaded connectors, ratchet-latch typestab in connector, or a standard threaded connection. In a preferredembodiment, the innerstring adapter 1910 is removably coupled to thedrill pipe 1905 by a drillpipe connection. The innerstring adapter 1910may be coupled to the sealing sleeve 1915 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connector, ratchet-latch type stab in connectors, or astandard threaded connection. In a preferred embodiment, the innerstringadapter 1910 is removably coupled to the sealing sleeve 1915 by astandard threaded connection.

The innerstring adapter 1910 preferably includes a fluid passage 1980that is adapted to convey fluidic materials from the fluid passage 1975into the fluid passage 1985. In a preferred embodiment, the fluidpassage 1980 is adapted to convey fluidic materials such as, forexample, cement, drilling mud, epoxy, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The sealing sleeve 1915 is coupled to the innerstring adapter 1910 andthe inner sealing mandrel 1920. The sealing sleeve 1915 preferablycomprises a substantially hollow tubular member or members. The sealingsleeve 1915 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, carbon steel, low alloy steel, stainless steel or otherhigh strength materials. In a preferred embodiment, the sealing sleeve1915 is fabricated from oilfield country tubular goods in order tooptimally provide mechanical properties that substantially match theremaining components of the apparatus 1900.

The sealing sleeve 1915 may be coupled to the innerstring adapter 1910using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, ratchet-latch typestab in connection, or a standard threaded connection. In a preferredembodiment, the sealing sleeve 1915 is removably coupled to theinnerstring adapter 1910 by a standard threaded connection. The sealingsleeve 1915 may be coupled to the inner sealing mandrel 1920 using anynumber of conventional commercially available mechanical couplings suchas, for example, drillpipe connection, oilfield country tubular goodsspecialty type threaded connection, or a standard threaded connection.In a preferred embodiment, the sealing sleeve 1915 is removably coupledto the inner sealing mandrel 1920 by a standard threaded connection.

The sealing sleeve 1915 preferably includes a fluid passage 1985 that isadapted to convey fluidic materials from the fluid passage 1980 into thefluid passage 1990. In a preferred embodiment, the fluid passage 1985 isadapted to convey fluidic materials such as, for example, cement,drilling mud, epoxy or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The inner sealing mandrel 1920 is coupled to the sealing sleeve 1915 andthe lower sealing head 1930. The inner sealing mandrel 1920 preferablycomprises a substantially hollow tubular member or members. The innersealing mandrel 1920 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, stainless steel, low alloy steel, carbon steel or othersimilar high strength materials. In a preferred embodiment, the innersealing mandrel 1920 is fabricated from stainless steel in order tooptimally provide mechanical properties similar to the other componentsof the apparatus 1900 while also providing a smooth outer surface tosupport seals and other moving parts that can operate with minimal wear,corrosion and pitting.

The inner sealing mandrel 1920 may be coupled to the sealing sleeve 1915using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnection. In a preferred embodiment, the inner sealing mandrel 1920 isremovably coupled to the sealing sleeve 1915 by a standard threadedconnections. The inner sealing mandrel 1920 may be coupled to the lowersealing head 1930 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet latch type stab in connectors or standard threadedconnections. In a preferred embodiment, the inner sealing mandrel 1920is removably coupled to the lower sealing head 1930 by a standardthreaded connections connection.

The inner sealing mandrel 1920 preferably includes a fluid passage 1990that is adapted to convey fluidic materials from the fluid passage 1985into the fluid passage 1995. In a preferred embodiment, the fluidpassage 1990 is adapted to convey fluidic materials such as, forexample, cement, drilling mud, epoxy or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The upper sealing head 1925 is coupled to the outer sealing mandrel 1935and the expansion cone 1945. The upper sealing head 1925 is also movablycoupled to the outer surface of the inner sealing mandrel 1920 and theinner surface of the casing 1970. In this manner, the upper sealing head1925, outer sealing mandrel 1935, and the expansion cone 1945reciprocate in the axial direction. The radial clearance between theinner cylindrical surface of the upper sealing head 1925 and the outersurface of the inner sealing mandrel 1920 may range, for example, fromabout 0.025 to 0.05 inches. In a preferred embodiment, the radialclearance between the inner cylindrical surface of the upper sealinghead 1925 and the outer surface of the inner sealing mandrel 1920 rangesfrom about 0.005 to 0.01 inches in order to optimally provide clearancefor pressure seal placement. The radial clearance between the outercylindrical surface of the upper sealing head 1925 and the inner surfaceof the casing 1970 may range, for example, from about 0.025 to 0.375inches. In a preferred embodiment, the radial clearance between theouter cylindrical surface of the upper sealing head 1925 and the innersurface of the casing 1970 ranges from about 0.025 to 0.125 inches inorder to optimally provide stabilization for the expansion cone 1945 asthe expansion cone 1945 is upwardly moved inside the casing 1970.

The upper sealing head 1925 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The uppersealing head 1925 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, stainless steel, machine tool steel, or similar highstrength materials. In a preferred embodiment, the upper sealing head1925 is fabricated from stainless steel in order to optimally providehigh strength and smooth outer surfaces that are resistant to wear,galling, corrosion and pitting.

The inner surface of the upper sealing head 1925 preferably includes oneor more annular sealing members 2000 for sealing the interface betweenthe upper sealing head 1925 and the inner sealing mandrel 1920. Thesealing members 2000 may comprise any number of conventionalcommercially available annular sealing members such as, for example,o-rings, polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 2000 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for a long axialmotion.

In a preferred embodiment, the upper sealing head 1925 includes ashoulder 2005 for supporting the upper sealing head 1925 on the lowersealing head 1930.

The upper sealing head 1925 may be coupled to the outer sealing mandrel1935 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnections. In a preferred embodiment, the upper sealing head 1925 isremovably coupled to the outer sealing mandrel 1935 by a standardthreaded connections. In a preferred embodiment, the mechanical couplingbetween the upper sealing head 1925 and the outer sealing mandrel 1935includes one or more sealing members 2010 for fluidicly sealing theinterface between the upper sealing head 1925 and the outer sealingmandrel 1935. The sealing members 2010 may comprise any number ofconventional commercially available sealing members such as, forexample, o-rings, polypak seals or metal spring energized seals. In apreferred embodiment, the sealing members 2010 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroking motion.

The lower sealing head 1930 is coupled to the inner sealing mandrel 1920and the load mandrel 1940. The lower sealing head 1930 is also movablycoupled to the inner surface of the outer sealing mandrel 1935. In thismanner, the upper sealing head 1925 and outer sealing mandrel 1935reciprocate in the axial direction. The radial clearance between theouter surface of the lower sealing head 1930 and the inner surface ofthe outer sealing mandrel 1935 may range, for example, from about 0.025to 0.05 inches. In a preferred embodiment, the radial clearance betweenthe outer surface of the lower sealing head 1930 and the inner surfaceof the outer sealing mandrel 1935 ranges from about 0.005 to 0.010inches in order to optimally provide a close tolerance having room forthe installation of pressure seal rings.

The lower sealing head 1930 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The lowersealing head 1930 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, stainless steel, machine tool steel or other similar highstrength materials. In a preferred embodiment, the lower sealing head1930 is fabricated from stainless steel in order to optimally providehigh strength and resistance to wear, galling, corrosion, and pitting.

The outer surface of the lower sealing head 1930 preferably includes oneor more annular sealing members 2015 for sealing the interface betweenthe lower sealing head 1930 and the outer sealing mandrel 1935. Thesealing members 2015 may comprise any number of conventionalcommercially available annular sealing members such as, for example,o-rings, polypak seals, or metal spring energized seals. In a preferredembodiment, the sealing members 2015 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for a long axialstroke.

The lower sealing head 1930 may be coupled to the inner sealing mandrel1920 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding or a standard threaded connection. In a preferred embodiment,the lower sealing head 1930 is removably coupled to the inner sealingmandrel 1920 by a standard threaded connection.

In a preferred embodiment, the mechanical coupling between the lowersealing head 1930 and the inner sealing mandrel 1920 includes one ormore sealing members 2020 for fluidicly sealing the interface betweenthe lower sealing head 1930 and the inner sealing mandrel 1920. Thesealing members 2020 may comprise any number of conventionalcommercially available sealing members such as, for example, o-rings,polypak seals, or metal spring energized seals. In a preferredembodiment, the sealing members 2020 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for a long axialmotion.

The lower sealing head 1930 may be coupled to the load mandrel 1940using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connections, welding, amorphousbonding or a standard threaded connection. In a preferred embodiment,the lower sealing head 1930 is removably coupled to the load mandrel1940 by a standard threaded connection. In a preferred embodiment, themechanical coupling between the lower sealing head 1930 and the loadmandrel 1940 includes one or more sealing members 2025 for fluidiclysealing the interface between the lower sealing head 1930 and the loadmandrel 1940. The sealing members 2025 may comprise any number ofconventional commercially available sealing members such as, forexample, o-rings, polypak seals, or metal spring energized seals. In apreferred embodiment, the sealing members 2025 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

In a preferred embodiment, the lower sealing head 1930 includes a throatpassage 2040 fluidicly coupled between the fluid passages 1990 and 1995.The throat passage 2040 is preferably of reduced size and is adapted toreceive and engage with a plug 2045, or other similar device. In thismanner, the fluid passage 1990 is fluidicly isolated from the fluidpassage 1995. In this manner, the pressure chamber 2030 is pressurized.

The outer sealing mandrel 1935 is coupled to the upper sealing head 1925and the expansion cone 1945. The outer sealing mandrel 1935 is alsomovably coupled to the inner surface of the casing 1970 and the outersurface of the lower sealing head 1930. In this manner, the uppersealing head 1925, outer sealing mandrel 1935, and the expansion cone1945 reciprocate in the axial direction. The radial clearance betweenthe outer surface of the outer sealing mandrel 1935 and the innersurface of the casing 1970 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer surface of the outer sealing mandrel 1935 and the innersurface of the casing 1970 ranges from about 0.025 to 0.125 inches inorder to optimally provide maximum piston surface area to maximize theradial expansion force. The radial clearance between the inner surfaceof the outer sealing mandrel 1935 and the outer surface of the lowersealing head 1930 may range, for example, from about 0.025 to 0.05inches. In a preferred embodiment, the radial clearance between theinner surface of the outer sealing mandrel 1935 and the outer surface ofthe lower sealing head 1930 ranges from about 0.005 to 0.010 inches inorder to optimally provide a minimum gap for the sealing elements tobridge and seal.

The outer sealing mandrel 1935 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The outersealing mandrel 1935 may be fabricated from any number of conventionalcommercially available materials such as, for example, low alloy steel,carbon steel, 13 chromium steel or stainless steel. In a preferredembodiment, the outer sealing mandrel 1935 is fabricated from stainlesssteel in order to optimally provide maximum strength and minimum wallthickness while also providing resistance to corrosion, galling andpitting.

The outer sealing mandrel 1935 may be coupled to the upper sealing head1925 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, standard threadedconnections, or welding. In a preferred embodiment, the outer sealingmandrel 1935 is removably coupled to the upper sealing head 1925 by astandard threaded connections connection. The outer sealing mandrel 1935may be coupled to the expansion cone 1945 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, or a standard threaded connections connection,or welding. In a preferred embodiment, the outer sealing mandrel 1935 isremovably coupled to the expansion cone 1945 by a standard threadedconnections connection.

The upper sealing head 1925, the lower sealing head 1930, the innersealing mandrel 1920, and the outer sealing mandrel 1935 together definea pressure chamber 2030. The pressure chamber 2030 is fluidicly coupledto the passage 1990 via one or more passages 2035. During operation ofthe apparatus 1900, the plug 2045 engages with the throat passage 2040to fluidicly isolate the fluid passage 1990 from the fluid passage 1995.The pressure chamber 2030 is then pressurized which in turn causes theupper sealing head 1925, outer sealing mandrel 1935, and expansion cone1945 to reciprocate in the axial direction. The axial motion of theexpansion cone 1945 in turn expands the casing 1970 in the radialdirection.

The load mandrel 1940 is coupled to the lower sealing head 1930 and themechanical slip body 1955. The load mandrel 1940 preferably comprises anannular member having substantially cylindrical inner and outersurfaces. The load mandrel 1940 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the load mandrel 1940 is fabricated from oilfield countrytubular goods in order to optimally provide high strength.

The load mandrel 1940 may be coupled to the lower sealing head 1930using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding or a standard threaded connection. In a preferred embodiment,the load mandrel 1940 is removably coupled to the lower sealing head1930 by a standard threaded connection. The load mandrel 1940 may becoupled to the mechanical slip body 1955 using any number ofconventional commercially available mechanical couplings such as, forexample, a drillpipe connection, oilfield country tubular goodsspecialty type threaded connections, welding, amorphous bonding, or astandard threaded connections connection. In a preferred embodiment, theload mandrel 1940 is removably coupled to the mechanical slip body 1955by a standard threaded connections connection.

The load mandrel 1940 preferably includes a fluid passage 1995 that isadapted to convey fluidic materials from the fluid passage 1990 to theregion outside of the apparatus 1900. In a preferred embodiment, thefluid passage 1995 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The expansion cone 1945 is coupled to the outer sealing mandrel 1935.The expansion cone 1945 is also movably coupled to the inner surface ofthe casing 1970. In this manner, the upper sealing head 1925, outersealing mandrel 1935, and the expansion cone 1945 reciprocate in theaxial direction. The reciprocation of the expansion cone 1945 causes thecasing 1970 to expand in the radial direction.

The expansion cone 1945 preferably comprises an annular member havingsubstantially cylindrical inner and conical outer surfaces. The outsideradius of the outside conical surface may range, for example, from about2 to 34 inches. In a preferred embodiment, the outside radius of theoutside conical surface ranges from about 3 to 28 inches in order tooptimally provide cone dimensions for the typical range of tubularmembers.

The axial length of the expansion cone 1945 may range, for example, fromabout 2 to 8 times the largest outer diameter of the expansion cone1945. In a preferred embodiment, the axial length of the expansion cone1945 ranges from about 3 to 5 times the largest outer diameter of theexpansion cone 1945 in order to optimally provide stability andcentralization of the expansion cone 1945 during the expansion process.In a preferred embodiment, the angle of attack of the expansion cone1945 ranges from about 5 to 30 degrees in order to optimally balancefriction forces with the desired amount of radial expansion. Theexpansion cone 1945 angle of attack will vary as a function of theoperating parameters of the particular expansion operation.

The expansion cone 1945 may be fabricated from any number ofconventional commercially available materials such as, for example,machine tool steel, ceramics, tungsten carbide, nitride steel, or othersimilar high strength materials. In a preferred embodiment, theexpansion cone 1945 is fabricated from D2 machine tool steel in order tooptimally provide high strength and resistance to corrosion, wear,galling, and pitting. In a particularly preferred embodiment, theoutside surface of the expansion cone 1945 has a surface hardnessranging from about 58 to 62 Rockwell C in order to optimally providehigh strength and resist wear and galling.

The expansion cone 1945 may be coupled to the outside sealing mandrel1935 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield tubularcountry goods specialty type threaded connection, welding, amorphousbonding, or a standard threaded connections connection. In a preferredembodiment, the expansion cone 1945 is coupled to the outside sealingmandrel 1935 using a standard threaded connections connection in orderto optimally provide connector strength for the typical operatingloading conditions while also permitting easy replacement of theexpansion cone 1945.

The mandrel launcher 1950 is coupled to the casing 1970. The mandrellauncher 1950 comprises a tubular section of casing having a reducedwall thickness compared to the casing 1970. In a preferred embodiment,the wall thickness of the mandrel launcher is about 50 to 100% of thewall thickness of the casing 1970. In this manner, the initiation of theradial expansion of the casing 1970 is facilitated, and the insertion ofthe larger outside diameter mandrel launcher 1950 into the wellboreand/or casing is facilitated.

The mandrel launcher 1950 may be coupled to the casing 1970 using anynumber of conventional mechanical couplings. The mandrel launcher 1950may have a wall thickness ranging, for example, from about 0.15 to 1.5inches. In a preferred embodiment, the wall thickness of the mandrellauncher 1950 ranges from about 0.25 to 0.75 inches in order tooptimally provide high strength with a small overall profile. Themandrel launcher 1950 may be fabricated from any number of conventionalcommercially available materials such as, for example, oil field tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the mandrel launcher1950 is fabricated from oil field tubular goods of higher strength butlower wall thickness than the casing 1970 in order to optimally providea thin walled container with approximately the same burst strength asthe casing 1970.

The mechanical slip body 1955 is coupled to the load mandrel 1970, themechanical slips 1960, and the drag blocks 1965. The mechanical slipbody 1955 preferably comprises a tubular member having an inner passage2050 fluidicly coupled to the passage 1995. In this manner, fluidicmaterials may be conveyed from the passage 2050 to a region outside ofthe apparatus 1900.

The mechanical slip body 1955 may be coupled to the load mandrel 1940using any number of conventional mechanical couplings. In a preferredembodiment, the mechanical slip body 1955 is removably coupled to theload mandrel 1940 using a standard threaded connection in order tooptimally provide high strength and permit the mechanical slip body 1955to be easily replaced. The mechanical slip body 1955 may be coupled tothe mechanical slips 1955 using any number of conventional mechanicalcouplings. In a preferred embodiment, the mechanical slip body 1955 isremovably coupled to the mechanical slips 1955 using threads and slidingsteel retainer rings in order to optimally provide high strengthcoupling and also permit easy replacement of the mechanical slips 1955.The mechanical slip body 1955 may be coupled to the drag blocks 1965using any number of conventional mechanical couplings. In a preferredembodiment, the mechanical slip body 1955 is removably coupled to thedrag blocks 1965 using threaded connections and sliding steel retainerrings in order to optimally provide high strength and also permit easyreplacement of the drag blocks 1965.

The mechanical slips 1960 are coupled to the outside surface of themechanical slip body 1955. During operation of the apparatus 1900, themechanical slips 1960 prevent upward movement of the casing 1970 andmandrel launcher 1950. In this manner, during the axial reciprocation ofthe expansion cone 1945, the casing 1970 and mandrel launcher 1950 aremaintained in a substantially stationary position. In this manner, themandrel launcher 1950 and casing 1970 are expanded in the radialdirection by the axial movement of the expansion cone 1945.

The mechanical slips 1960 may comprise any number of conventionalcommercially available mechanical slips such as, for example, RTTSpacker tungsten carbide mechanical slips, RTTS packer wicker typemechanical slips or Model 3L retrievable bridge plug tungsten carbideupper mechanical slips. In a preferred embodiment, the mechanical slips1960 comprise RTTS packer tungsten carbide mechanical slips availablefrom Halliburton Energy Services in order to optimally provideresistance to axial movement of the casing 1970 during the expansionprocess.

The drag blocks 1965 are coupled to the outside surface of themechanical slip body 1955. During operation of the apparatus 1900, thedrag blocks 1965 prevent upward movement of the casing 1970 and mandrellauncher 1950. In this manner, during the axial reciprocation of theexpansion cone 1945, the casing 1970 and mandrel launcher 1950 aremaintained in a substantially stationary position. In this manner, themandrel launcher 1950 and casing 1970 are expanded in the radialdirection by the axial movement of the expansion cone 1945.

The drag blocks 1965 may comprise any number of conventionalcommercially available mechanical slips such as, for example, RTTSpacker tungsten carbide mechanical slips, RTTS packer wicker typemechanical slips or Model 3L retrievable bridge plug tungsten carbideupper mechanical slips. In a preferred embodiment, the drag blocks 1965comprise RTTS packer tungsten carbide mechanical slips available fromHalliburton Energy Services in order to optimally provide resistance toaxial movement of the casing 1970 during the expansion process.

The casing 1970 is coupled to the mandrel launcher 1950. The casing 1970is further removably coupled to the mechanical slips 1960 and dragblocks 1965. The casing 1970 preferably comprises a tubular member. Thecasing 1970 may be fabricated from any number of conventionalcommercially available materials such as, for example, slotted tubulars,oil field country tubular goods, low alloy steel, carbon steel,stainless steel or other similar high strength materials. In a preferredembodiment, the casing 1970 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide high strength. In a preferred embodiment, the upperend of the casing 1970 includes one or more sealing members positionedabout the exterior of the casing 1970.

During operation, the apparatus 1900 is positioned in a wellbore withthe upper end of the casing 1970 positioned in an overlappingrelationship within an existing wellbore casing. In order minimize surgepressures within the borehole during placement of the apparatus 1900,the fluid passage 1975 is preferably provided with one or more pressurerelief passages. During the placement of the apparatus 1900 in thewellbore, the casing 1970 is supported by the expansion cone 1945.

After positioning of the apparatus 1900 within the bore hole in anoverlapping relationship with an existing section of wellbore casing, afirst fluidic material is pumped into the fluid passage 1975 from asurface location. The first fluidic material is conveyed from the fluidpassage 1975 to the fluid passages 1980, 1985, 1990, 1995, and 2050. Thefirst fluidic material will then exit the apparatus and fill the annularregion between the outside of the apparatus 1900 and the interior wallsof the bore hole.

The first fluidic material may comprise any number of conventionalcommercially available materials such as, for example, drilling mud,water, epoxy or cement. In a preferred embodiment, the first fluidicmaterial comprises a hardenable fluidic sealing material such as, forexample, cement or epoxy. In this manner, a wellbore casing having anouter annular layer of a hardenable material may be formed.

The first fluidic material may be pumped into the apparatus 1900 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi, and 0 to 3,000 gallons/minute. In a preferred embodiment, thefirst fluidic material is pumped into the apparatus 1900 at operatingpressures and flow rates ranging from about 0 to 4,500 psi and 0 to3,000 gallons/minute in order to optimally provide operating pressuresand flow rates for typical operating conditions.

At a predetermined point in the injection of the first fluidic materialsuch as, for example, after the annular region outside of the apparatus1900 has been filled to a predetermined level, a plug 2045, dart, orother similar device is introduced into the first fluidic material. Theplug 2045 lodges in the throat passage 2040 thereby fluidicly isolatingthe fluid passage 1990 from the fluid passage 1995.

After placement of the plug 2045 in the throat passage 2040, a secondfluidic material is pumped into the fluid passage 1975 in order topressurize the pressure chamber 2030. The second fluidic material maycomprise any number of conventional commercially available materialssuch as, for example, water, drilling gases, drilling mud or lubricant.In a preferred embodiment, the second fluidic material comprises anon-hardenable fluidic material such as, for example, water, drillingmud or lubricant in order minimize frictional forces.

The second fluidic material may be pumped into the apparatus 1900 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thesecond fluidic material is pumped into the apparatus 1900 at operatingpressures and flow rates ranging from about 0 to 3,500 psi, and 0 to1,200 gallons/minute in order to optimally provide expansion of thecasing 1970.

The pressurization of the pressure chamber 2030 causes the upper sealinghead 1925, outer sealing mandrel 1935, and expansion cone 1945 to movein an axial direction. As the expansion cone 1945 moves in the axialdirection, the expansion cone 1945 pulls the mandrel launcher 1950 anddrag blocks 1965 along, which sets the mechanical slips 1960 and stopsfurther axial movement of the mandrel launcher 1950 and casing 1970. Inthis manner, the axial movement of the expansion cone 1945 radiallyexpands the mandrel launcher 1950 and casing 1970.

Once the upper sealing head 1925, outer sealing mandrel 1935, andexpansion cone 1945 complete an axial stroke, the operating pressure ofthe second fluidic material is reduced and the drill string 1905 israised. This causes the inner sealing mandrel 1920, lower sealing head1930, load mandrel 1940, and mechanical slip body 1955 to move upward.This unsets the mechanical Blips 1960 and permits the mechanical slips1960 and drag blocks 1965 to be moved upward within the mandrel launcherand casing 1970. When the lower sealing head 1930 contacts the uppersealing head 1925, the second fluidic material is again pressurized andthe radial expansion process continues. In this manner, the mandrellauncher 1950 and casing 1970 are radial expanded through repeated axialstrokes of the upper sealing head 1925, outer sealing mandrel 1935 andexpansion cone 1945. Throughput the radial expansion process, the upperend of the casing 1970 is preferably maintained in an overlappingrelation with an existing section of wellbore casing.

At the end of the radial expansion process, the upper end of the casing1970 is expanded into intimate contact with the inside surface of thelower end of the existing wellbore casing. In a preferred embodiment,the sealing members provided at the upper end of the casing 1970 providea fluidic seal between the outside surface of the upper end of thecasing 1970 and the inside surface of the lower end of the existingwellbore casing. In a preferred embodiment, the contact pressure betweenthe casing 1970 and the existing section of wellbore casing ranges fromabout 400 to 10,000 psi in order to optimally provide contact pressurefor activating sealing members, provide optimal resistance to axialmovement of the expanded casing 1970, and optimally support typicaltensile and compressive loads.

In a preferred embodiment, as the expansion cone 1945 nears the end ofthe casing 1970, the operating flow rate of the second fluidic materialis reduced in order to minimize shock to the apparatus 1900. In analternative embodiment, the apparatus 1900 includes a shock absorber forabsorbing the shock created by the completion of the radial expansion ofthe casing 1970.

In a preferred embodiment, the reduced operating pressure of the secondfluidic material ranges from about 100 to 1,000 psi as the expansioncone 1945 nears the end of the casing 1970 in order to optimally providereduced axial movement and velocity of the expansion cone 1945. In apreferred embodiment, the operating pressure of the second fluidicmaterial is reduced during the return stroke of the apparatus 1900 tothe range of about 0 to 500 psi in order minimize the resistance to themovement of the expansion cone 1945. In a preferred embodiment, thestroke length of the apparatus 1900 ranges from about 10 to 45 feet inorder to optimally provide equipment lengths that can be handled bytypical oil well rigging equipment while also minimizing the frequencyat which the expansion cone 1945 must be stopped so the apparatus 1900can be re-stroked for further expansion operations.

In an alternative embodiment, at least a portion of the upper sealinghead 1925 includes an expansion cone for radially expanding the mandrellauncher 1950 and casing 1970 during operation of the apparatus 1900 inorder to increase the surface area of the casing 1970 acted upon duringthe radial expansion process. In this manner, the operating pressurescan be reduced.

In an alternative embodiment, mechanical slips are positioned in anaxial location between the sealing sleeve 1915 and the inner sealingmandrel 1920 in order to simplify the operation and assembly of theapparatus 1900.

Upon the complete radial expansion of the casing 1970, if applicable,the first fluidic material is permitted to cure within the annularregion between the outside of the expanded casing 1970 and the interiorwalls of the wellbore. In the case where the expanded casing 1970 isslotted, the cured fluidic material will preferably permeate and envelopthe expanded casing. In this manner, a new section of wellbore casing isformed within a wellbore. Alternatively, the apparatus 1900 may be usedto join a first section of pipeline to an existing section of pipeline.Alternatively, the apparatus 1900 may be used to directly line theinterior of a wellbore with a casing, without the use of an outerannular layer of a hardenable material. Alternatively, the apparatus1900 may be used to expand a tubular support member in a hole.

During the radial expansion process, the pressurized areas of theapparatus 1900 are limited to the fluid passages 1975, 1980, 1985, and1990, and the pressure chamber 2030. No fluid pressure acts directly onthe mandrel launcher 1950 and casing 1970. This permits the use ofoperating pressures higher than the mandrel launcher 1950 and casing1970 could normally withstand.

Referring now to FIG. 16, a preferred embodiment of an apparatus 2100for forming a mono-diameter wellbore casing will be described. Theapparatus 2100 preferably includes a drillpipe 2105, an innerstringadapter 2110, a sealing sleeve 2115, an inner sealing mandrel 2120,slips 2125, upper sealing head 2130, lower sealing head 2135, outersealing mandrel 2140, load mandrel 2145, expansion cone 2150, and casing2155.

The drillpipe 2105 is coupled to the innerstring adapter 2110. Duringoperation of the apparatus 2100, the drillpipe 2105 supports theapparatus 2100. The drillpipe 2105 preferably comprises a substantiallyhollow tubular member or members. The drillpipe 2105 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, oilfield country tubular goods, low alloy steel, carbonsteel, stainless steel or other similar high strength material. In apreferred embodiment, the drillpipe 2105 is fabricated from coiledtubing in order to faciliate the placement of the apparatus 1900 innon-vertical wellbores. The drillpipe 2105 may be coupled to theinnerstring adapter 2110 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type connection, or a standard threadedconnection. In a preferred embodiment, the drillpipe 2105 is removablycoupled to the innerstring adapter 2110 by a drill pipe connection.

The drillpipe 2105 preferably includes a fluid passage 2160 that isadapted to convey fluidic materials from a surface location into thefluid passage 2165. In a preferred embodiment, the fluid passage 2160 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The innerstring adapter 2110 is coupled to the drill string 2105 and thesealing sleeve 2115. The innerstring adapter 2110 preferably comprises asubstantially hollow tubular member or members. The innerstring adapter2110 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the innerstringadapter 2110 is fabricated from stainless steel in order to optimallyprovide high strength, low friction, and resistance to corrosion andwear.

The innerstring adapter 2110 may be coupled to the drill string 2105using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, ratchet-latch typeconnection or a standard threaded connection. In a preferred embodiment,the innerstring adapter 2110 is removably coupled to the drill pipe 2105by a drillpipe connection. The innerstring adapter 2110 may be coupledto the sealing sleeve 2115 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection, or a standardthreaded connection. In a preferred embodiment, the innerstring adapter2110 is removably coupled to the sealing sleeve 2115 by a standardthreaded connection.

The innerstring adapter 2110 preferably includes a fluid passage 2165that is adapted to convey fluidic materials from the fluid passage 2160into the fluid passage 2170. In a preferred embodiment, the fluidpassage 2165 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water drilling muds, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The sealing sleeve 2115 is coupled to the innerstring adapter 2110 andthe inner sealing mandrel 2120. The sealing sleeve 2115 preferablycomprises a substantially hollow tubular member or members. The sealingsleeve 2115 may be fabricated from any number of conventionalcommercially available materials such as, for example, oil field tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the sealing sleeve2115 is fabricated from stainless steel in order to optimally providehigh strength, low friction surfaces, and resistance to corrosion, wear,galling, and pitting.

The sealing sleeve 2115 may be coupled to the innerstring adapter 2110using any number of conventional commercially available mechanicalcouplings such as, for example, a standard threaded connection, oilfieldcountry tubular goods specialty type threaded connections, welding,amorphous bonding, or a standard threaded connection. In a preferredembodiment, the sealing sleeve 2115 is removably coupled to theinnerstring adapter 2110 by a standard threaded connection. The sealingsleeve 2115 may be coupled to the inner sealing mandrel 2120 using anynumber of conventional commercially available mechanical couplings suchas, for example, a standard threaded connection, oilfield countrytubular goods specialty type threaded connections, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the sealing sleeve 2115 is removably coupled to the inner sealingmandrel 2120 by a standard threaded connection.

The sealing sleeve 2115 preferably includes a fluid passage 2170 that isadapted to convey fluidic materials from the fluid passage 2165 into thefluid passage 2175. In a preferred embodiment, the fluid passage 2170 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud, or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The inner sealing mandrel 2120 is coupled to the sealing sleeve 2115,slips 2125, and the lower sealing head 2135. The inner sealing mandrel2120 preferably comprises a substantially hollow tubular member ormembers. The inner sealing mandrel 2120 may be fabricated from anynumber of conventional commercially available materials such as, forexample, oilfield country tubular goods, low alloy steel, carbon steel,stainless steel or other similar high strength materials. In a preferredembodiment, the inner sealing mandrel 2120 is fabricated from stainlesssteel in order to optimally provide high strength, low frictionsurfaces, and corrosion and wear resistance.

The inner sealing mandrel 2120 may be coupled to the sealing sleeve 2115using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnection. In a preferred embodiment, the inner sealing mandrel 2120 isremovably coupled to the sealing sleeve 2115 by a standard threadedconnection. The standard threaded connection provides high strength andpermits easy replacement of components. The inner sealing mandrel 2120may be coupled to the slips 2125 using any number of conventionalcommercially available mechanical couplings such as, for example,welding, amorphous bonding, or a standard threaded connection. In apreferred embodiment, the inner sealing mandrel 2120 is removablycoupled to the slips 2125 by a standard threaded connection. The innersealing mandrel 2120 may be coupled to the lower sealing head 2135 usingany number of conventional commercially available mechanical couplingssuch as, for example, drillpipe connection, oilfield country tubulargoods specialty type threaded connection, welding, amorphous bonding ora standard threaded connection. In a preferred embodiment, the innersealing mandrel 2120 is removably coupled to the lower sealing head 2135by a standard threaded connection.

The inner sealing mandrel 2120 preferably includes a fluid passage 2175that is adapted to convey fluidic materials from the fluid passage 2170into the fluid passage 2180. In a preferred embodiment, the fluidpassage 2175 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The slips 2125 are coupled to the outer surface of the inner sealingmandrel 2120. During operation of the apparatus 2100, the slips 2125preferably maintain the casing 2155 in a substantially stationaryposition during the radial expansion of the casing 2155. In a preferredembodiment, the slips 2125 are activated using the fluid passages 2185to convey pressurized fluid material into the slips 2125.

The slips 2125 may comprise any number of commercially availablehydraulic slips such as, for example, RTTS packer tungsten carbidehydraulic slips or Model 3L retrievable bridge plug hydraulic slips. Ina preferred embodiment, the slips 2125 comprise RTTS packer tungstencarbide hydraulic slips available from Halliburton Energy Services inorder to optimally provide resistance to axial movement of the casing2155 during the expansion process. In a particularly preferredembodiment, the slips include a fluid passage 2190, pressure chamber2195, spring return 2200, and slip member 2205.

The slips 2125 may be coupled to the inner sealing mandrel 2120 usingany number of conventional mechanical couplings. In a preferredembodiment, the slips 2125 are removably coupled to the outer surface ofthe inner sealing mandrel 2120 by a thread connection in order tooptimally provide interchangeability of parts.

The upper sealing head 2130 is coupled to the outer sealing mandrel 2140and expansion cone 2150. The upper sealing head 2130 is also movablycoupled to the outer surface of the inner sealing mandrel 2120 and theinner surface of the casing 2155. In this manner, the upper sealing head2130 reciprocates in the axial direction. The radial clearance betweenthe inner cylindrical surface of the upper sealing head 2130 and theouter surface of the inner sealing mandrel 2120 may range, for example,from about 0.025 to 0.05 inches. In a preferred embodiment, the radialclearance between the inner cylindrical surface of the upper sealinghead 2130 and the outer surface of the inner sealing mandrel 2120 rangesfrom about 0.005 to 0.010 inches in order to optimally provide apressure seal. The radial clearance between the outer cylindricalsurface of the upper sealing head 2130 and the inner surface of thecasing 2156 may range, for example, from about 0.025 to 0.375 inches. Ina preferred embodiment, the radial clearance between the outercylindrical surface of the upper sealing head 2130 and the inner surfaceof the casing 2155 ranges from about 0.025 to 0.125 inches in order tooptimally provide stabilization for the expansion cone 2130 during axialmovement of the expansion cone 2130.

The upper sealing head 2130 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The uppersealing head 2130 may be fabricated from any number of conventionalcommercially available materials such as, for example, low alloy steel,carbon steel, stainless steel or other similar high strength materials.In a preferred embodiment, the upper sealing head 2130 is fabricatedfrom stainless steel in order to optimally provide high strength,corrosion resistance, and low friction surfaces. The inner surface ofthe upper sealing head 2130 preferably includes one or more annularsealing members 2210 for sealing the interface between the upper sealinghead 2130 and the inner sealing mandrel 2120. The sealing members 2210may comprise any number of conventional commercially available annularsealing members such as, for example, o-rings, polypak seals, or metalspring energized seals. In a preferred embodiment, the sealing members2210 comprise polypak seals available from Parker Seals in order tooptimally provide sealing for a long axial stroke.

In a preferred embodiment, the upper sealing head 2130 includes ashoulder 2215 for supporting the upper sealing head 2130 on the lowersealing head 2135.

The upper sealing head 2130 may be coupled to the outer sealing mandrel2140 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, the uppersealing head 2130 is removably coupled to the outer sealing mandrel 2140by a standard threaded connection. In a preferred embodiment, themechanical coupling between the upper sealing head 2130 and the outersealing mandrel 2140 includes one or more sealing members 2220 forfluidicly sealing the interface between the upper sealing head 2130 andthe outer sealing mandrel 2140. The sealing members 2220 may compriseany number of conventional commercially available sealing members suchas, for example, o-rings, polypak seals, or metal spring energizedseals. In a preferred embodiment, the sealing members 2220 comprisepolypak seals available from Parker Seals in order to optimally providesealing for a long axial stroke.

The lower sealing head 2135 is coupled to the inner sealing mandrel 2120and the load mandrel 2145. The lower sealing head 2135 is also movablycoupled to the inner surface of the outer sealing mandrel 2140. In thismanner, the upper sealing head 2130, outer sealing mandrel 2140, andexpansion cone 2150 reciprocate in the axial direction. The radialclearance between the outer surface of the lower sealing head 2135 andthe inner surface of the outer sealing mandrel 2140 may range, forexample, from about 0.0025 to 0.05 inches. In a preferred embodiment,the radial clearance between the outer surface of the lower sealing head2135 and the inner surface of the outer sealing mandrel 2140 ranges fromabout 0.0025 to 0.05 inches in order to optimally provide minimal radialclearance.

The lower sealing head 2135 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The lowersealing head 2135 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the lowersealing head 2135 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces. The outer surface of the lower sealing head 2135 preferablyincludes one or more annular sealing members 2225 for sealing theinterface between the lower sealing head 2135 and the outer sealingmandrel 2140. The sealing members 2225 may comprise any number ofconventional commercially available annular sealing members such as, forexample, o-rings, polypak seals or metal spring energized seals. In apreferred embodiment, the sealing members 2225 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

The lower sealing head 2135 may be coupled to the inner sealing mandrel2120 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the lower sealing head 2135 is removably coupled to the inner sealingmandrel 2120 by a standard threaded connection. In a preferredembodiment, the mechanical coupling between the lower sealing head 2135and the inner sealing mandrel 2120 includes one or more sealing members2230 for fluidicly sealing the interface between the lower sealing head2135 and the inner sealing mandrel 2120. The sealing members 2230 maycomprise any number of conventional commercially available sealingmembers such as, for example, o-rings, polypak seals, or metal springenergized seals. In a preferred embodiment, the sealing members 2230comprise polypak seals available from Parker Seals in order to optimallyprovide sealing for a long axial stroke.

The lower sealing head 2135 may be coupled to the load mandrel 2145using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, the lowersealing head 2135 is removably coupled to the load mandrel 2145 by astandard threaded connection. In a preferred embodiment, the mechanicalcoupling between the lower sealing head 2135 and the load mandrel 2145includes one or more sealing members 2235 for fluidicly sealing theinterface between the lower sealing head 1930 and the load mandrel 2145.The sealing members 2235 may comprise any number of conventionalcommercially available sealing members such as; for example, o-rings,polypak seals, or metal spring energized seals. In a preferredembodiment, the sealing members 2235 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for a long axialstroke.

In a preferred embodiment, the lower sealing head 2135 includes a throatpassage 2240 fluidicly coupled between the fluid passages 2175 and 2180.The throat passage 2240 is preferably of reduced size and is adapted toreceive and engage with a plug 2245, or other similar device. In thismanner, the fluid passage 2175 is fluidicly isolated from the fluidpassage 2180. In this manner, the pressure chamber 2250 is pressurized.

The outer sealing mandrel 2140 is coupled to the upper sealing head 2130and the expansion cone 2150. The outer sealing mandrel 2140 is alsomovably coupled to the inner surface of the casing 2155 and the outersurface of the lower sealing head 2135. In this manner, the uppersealing head 2130, outer sealing mandrel 2140, and the expansion cone2150 reciprocate in the axial direction. The radial clearance betweenthe outer surface of the outer sealing mandrel 2140 and the innersurface of the casing 2155 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer surface of the outer sealing mandrel 2140 and the innersurface of the casing 2155 ranges from about 0.025 to 0.125 inches inorder to optimally provide stabilization for the expansion cone 2130during the expansion process. The radial clearance between the innersurface of the outer sealing mandrel 2140 and the outer surface of thelower sealing head 2135 may range, for example, from about 0.005 to0.125 inches. In a preferred embodiment, the radial clearance betweenthe inner surface of the outer sealing mandrel 2140 and the outersurface of the lower sealing head 2135 ranges from about 0.005 to 0.010inches in order to optimally provide minimal radial clearance.

The outer sealing mandrel 2140 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The outersealing mandrel 2140 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel, or othersimilar high strength materials. In a preferred embodiment, the outersealing mandrel 2140 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces.

The outer sealing mandrel 2140 may be coupled to the upper sealing head2130 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, the outersealing mandrel 2140 is removably coupled to the upper sealing head 2130by a standard threaded connection. The outer sealing mandrel 2140 may becoupled to the expansion cone 2150 using any number of conventionalcommercially available mechanical couplings such as, for example,drillpipe connection, oilfield country tubular goods specialty threadedconnection, welding, amorphous bonding, or a standard threadedconnection. In a preferred embodiment, the outer sealing mandrel 2140 isremovably coupled to the expansion cone 2150 by a standard threadedconnection.

The upper sealing head 2130, the lower sealing head 2135, inner sealingmandrel 2120, and the outer sealing mandrel 2140 together define apressure chamber 2250. The pressure chamber 2250 is fluidicly coupled tothe passage 2175 via one or more passages 2255. During operation of theapparatus 2100, the plug 2245 engages with the throat passage 2240 tofluidicly isolate the fluid passage 2175 from the fluid passage 2180.The pressure chamber 2250 is then pressurized which in turn causes theupper sealing head 2130, outer sealing mandrel 2140, and expansion cone2150 to reciprocate in the axial direction. The axial motion of theexpansion cone 2150 in turn expands the casing 2155 in the radialdirection.

The load mandrel 2145 is coupled to the lower sealing head 2135. Theload mandrel 2145 preferably comprises an annular member havingsubstantially cylindrical inner and outer surfaces. The load mandrel2145 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the load mandrel2145 is fabricated from stainless steel in order to optimally providehigh strength, corrosion resistance, and low friction bearing surfaces.

The load mandrel 2145 may be coupled to the lower sealing head 2135using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, the loadmandrel 2145 is removably coupled to the lower sealing head 2135 by astandard threaded connection in order to optimally provide high strengthand permit easy replacement of the load mandrel 2145.

The load mandrel 2145 preferably includes a fluid passage 2180 that isadapted to convey fluidic materials from the fluid passage 2180 to theregion outside of the apparatus 2100. In a preferred embodiment, thefluid passage 2180 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The expansion cone 2150 is coupled to the outer sealing mandrel 2140.The expansion cone 2150 is also movably coupled to the inner surface ofthe casing 2155. In this manner, the upper sealing head 2130, outersealing mandrel 2140, and the expansion cone 2150 reciprocate in theaxial direction. The reciprocation of the expansion cone 2150 causes thecasing 2155 to expand in the radial direction.

The expansion cone 2150 preferably comprises an annular member havingsubstantially cylindrical inner and conical outer surfaces. The outsideradius of the outside conical surface may range, for example, from about2 to 34 inches. In a preferred embodiment, the outside radius of theoutside conical surface ranges from about 3 to 28 inches in order tooptimally provide cone dimensions that are optimal for typical casings.The axial length of the expansion cone 2150 may range, for example, fromabout 2 to 6 times the largest outside diameter of the expansion cone2150. In a preferred embodiment, the axial length of the expansion cone2150 ranges from about 3 to 5 times the largest outside diameter of theexpansion cone 2150 in order to optimally provide stability andcentralization of the expansion cone 2150 during the expansion process.In a particularly preferred embodiment, the maximum outside diameter ofthe expansion cone 2150 is between about 90 to 100% of the insidediameter of the existing wellbore that the casing 2156 will be joinedwith. In a preferred embodiment, the angle of attack of the expansioncone 2150 ranges from about 5 to 30 degrees in order to optimallybalance friction forces and radial expansion forces. The optimalexpansion cone 2150 angle of attack will vary as a function of theparticular operating conditions of the expansion operation.

The expansion cone 2150 may be fabricated from any number ofconventional commercially available materials such as, for example,machine tool steel, nitride steel, titanium, tungsten carbide, ceramics,or other similar high strength materials. In a preferred embodiment, theexpansion cone 2150 is fabricated from D2 machine tool steel in order tooptimally provide high strength and resistance to wear and galling. In aparticularly preferred embodiment, the outside surface of the expansioncone 2150 has a surface hardness ranging from about 58 to 62 Rockwell Cin order to optimally provide resistance to wear.

The expansion cone 2150 may be coupled to-the outside sealing mandrel2140 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding or a standard threaded connection. In a preferred embodiment,the expansion cone 2150 is coupled to the a outside sealing mandrel 2140using a standard threaded connection in order to optimally provide highstrength and permit the expansion cone 2150 to be easily replaced.

The casing 2155 is removably coupled to the slips 2125 and expansioncone 2150. The casing 2155 preferably comprises a tubular member. Thecasing 2155 may be fabricated from any number of conventionalcommercially available materials such as, for example, slotted tubulars,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength material. In a preferredembodiment, the casing 2155 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide high strength.

In a preferred embodiment, the upper end 2260 of the casing 2155includes a thin wall section 2265 and an outer annular sealing member2270. In a preferred embodiment, the wall thickness of the thin wallsection 2265 is about 50 to 100% of the regular wall thickness of thecasing 2155. In this manner, the upper end 2260 of the casing 2155 maybe easily expanded and deformed into intimate contact with the lower endof an existing section of wellbore casing. In a preferred embodiment,the lower end of the existing section of casing also includes a thinwall section. In this manner, the radial expansion of the thin walledsection 2265 of casing 2155 into the thin walled section of the existingwellbore casing results in a wellbore casing having a substantiallyconstant inside diameter.

The annular sealing member 2270 may be fabricated from any number ofconventional commercially available sealing materials such as, forexample, epoxy, A rubber, metal or plastic. In a preferred embodiment,the annular sealing member 2270 is fabricated from StrataLock epoxy inorder to optimally provide compressibility and resistance to wear. Theoutside diameter of the annular sealing member 2270 preferably rangesfrom about 70 to 95% of the inside diameter of the lower section of thewellbore casing that the casing 2155 is joined to. In this manner, afterexpansion, the annular sealing member 2270 preferably provides a fluidicseal and also preferably provides sufficient frictional force with theinside surface of the A existing section of wellbore casing during theradial expansion of the casing 2155 to support the casing 2155.

In a preferred embodiment, the lower end 2275 of the casing 2155includes a thin wall section 2280 and an outer annular sealing member2285. In a preferred embodiment, the wall thickness of the thin wallsection 2280 is about 50 to 100% of the regular wall thickness of thecasing 2155. In this manner, the lower end 2275 of the casing 2155 maybe easily expanded and deformed. Furthermore, in this manner, an othersection of casing may be easily joined with the lower end 2275 of thecasing 2155 using a radial expansion process. In a preferred embodiment,the upper end of the other section of casing also includes a thin wallsection. In this manner, the radial expansion of the thin walled sectionof the upper end of the other casing into the thin walled section 2280of the lower end of the casing 2155 results in a wellbore casing havinga substantially constant inside diameter.

The annular sealing member 2285 may be fabricated from any number ofconventional commercially available sealing materials such as, forexample, epoxy, rubber, metal or plastic. In a preferred embodiment, theannular sealing member 2285 is fabricated from StrataLock epoxy in orderto optimally provide compressibility and wear resistance. The outsidediameter of the annular sealing member 2285 preferably ranges from about70 to 95% of the inside diameter of the lower section of the existingwellbore casing that the casing 2155 is joined to. In this manner, theannular sealing member 2285 preferably provides a fluidic seal and alsopreferably provides sufficient frictional force with the inside wall ofthe wellbore during the radial expansion of the casing 2155 to supportthe casing 2155.

During operation, the apparatus 2100 is preferably positioned in awellbore with the upper end 2260 of the casing 2155 positioned in anoverlapping relationship with the lower end of an existing wellborecasing. In a particularly preferred embodiment, the thin wall section2265 of the casing 2155 is positioned in opposing overlapping relationwith the thin wall section and outer annular sealing member of the lowerend of the existing section of wellbore casing. In this manner, theradial expansion of the casing 2155 will compress the thin wall sectionsand annular compressible members of the upper end 2260 of the casing2155 and the lower end of the existing wellbore casing into intimatecontact. During the positioning of the apparatus 2100 in the wellbore,the casing 2155 is supported by the expansion cone 2150.

After positioning of the apparatus 2100, a first fluidic material isthen pumped into the fluid passage 2160. The first fluidic material maycomprise any number of conventional commercially available materialssuch as, for example, drilling mud, water, epoxy, or cement. In apreferred embodiment, the first fluidic material comprises a hardenablefluidic sealing material such as, for example, cement or epoxy in orderto provide a hardenable outer annular body around the expanded casing2155.

The first fluidic material may be pumped into the fluid passage 2160 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 3,000 gallons/minute. In a preferred embodiment, thefirst fluidic material is pumped into the fluid passage 2160 atoperating pressures and flow rates ranging from about 0 to 3,500 psi and0 to 1,200 gallons/minute in order to optimally provide operationalefficiency.

The first fluidic material pumped into the fluid passage 2160 passesthrough the fluid passages 2165, 2170, 2175, 2180 and then outside ofthe apparatus 2100. The first fluidic material then fills the annularregion between the outside of the apparatus 2100 and the interior wallsof the wellbore.

The plug 2245 is then introduced into the fluid passage 2160. The plug2245 lodges in the throat passage 2240 and fluidicly isolates and blocksoff the fluid passage 2175. In a preferred embodiment, a couple ofvolumes of a non-hardenable fluidic material are then pumped into thefluid passage 2160 in order to remove any hardenable fluidic materialcontained within and to ensure that none of the fluid passages areblocked.

A second fluidic material is then pumped into the fluid passage 2160.The second fluidic material may comprise any number of conventionalcommercially available materials such as, for example, drilling mud,water, drilling gases, or lubricants. In a preferred embodiment, thesecond fluidic material comprises a non-hardenable fluidic material suchas, for example, water, drilling mud or lubricant in order to optimallyprovide pressurization of the pressure chamber 2250 and minimizefrictional forces.

The second fluidic material may be pumped into the fluid passage 2160 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thesecond fluidic material is pumped into the fluid passage 2160 atoperating pressures and flow rates ranging from about 0 to 3,500 psi and0 to 1,200 gallons/minute in order to optimally provide operationalefficiency.

The second fluidic material pumped into the fluid passage 2160 passesthrough the fluid passages 2165, 2170, and 2175 into the pressurechambers 2195 of the slips 2125, and into the pressure chamber 2250.Continued pumping of the second fluidic material pressurizes thepressure chambers 2195 and 2250.

The pressurization of the pressure chambers 2195 causes the slip members2205 to expand in the radial direction and grip the interior surface ofthe casing 2155. The casing 2155 is then preferably maintained in asubstantially stationary position.

The pressurization of the pressure chamber 2250 causes the upper sealinghead 2130, outer sealing mandrel 2140 and expansion cone 2150 to move inan axial direction relative to the casing 2155. In this manner, theexpansion cone 2150 will cause the casing 2155 to expand in the radialdirection.

During the radial expansion process, the casing 2155 is prevented frommoving in an upward direction by the slips 2125. A length of the casing2155 is then expanded in the radial direction through the pressurizationof the pressure chamber 2250. The length of the casing 2155 that isexpanded during the expansion process will be proportional to the strokelength of the upper sealing head 2130, outer sealing mandrel 2140, andexpansion cone 2150.

Upon the completion of a stroke, the operating pressure of the secondfluidic material is reduced and the upper sealing head 2130, outersealing mandrel 2140, and expansion cone 2150 drop to their restpositions with the casing 2155 supported by the expansion cone 2150. Theposition of the drillpipe 2105 is preferably adjusted throughout theradial expansion process in order to maintain the overlappingrelationship between the thin walled sections of the lower end of theexisting wellbore casing and the upper end of the casing 2155. In apreferred embodiment, the stroking of the expansion cone 2150 is thenrepeated, as necessary, until the thin walled section 2265 of the upperend 2260 of the casing 2155 is expanded into the thin walled section ofthe lower end of the existing wellbore casing. In this manner, awellbore casing is formed including two adjacent sections of casinghaving a substantially constant inside diameter. This process may thenbe repeated for the entirety of the wellbore to provide a wellborecasing thousands of feet in length having a substantially constantinside diameter.

In a preferred embodiment, during the final stroke of the expansion cone2150, the slips 2125 are positioned as close as possible to the thinwalled section 2265 of the upper end of the casing 2155 in orderminimize slippage between the casing 2155 and the existing wellborecasing at the end of the radial expansion process. Alternatively, or inaddition, the outside diameter of the annular sealing member 2270 isselected to ensure sufficient interference fit with the inside diameterof the lower end of the existing casing to prevent axial displacement ofthe casing 2155 during the final stroke. Alternatively, or in addition,the outside diameter of the annular sealing member 2285 is selected toprovide an interference fit with the inside walls of the wellbore at anearlier point in the radial expansion process so as to prevent furtheraxial displacement of the casing 2155. In this final alternative, theinterference fit is preferably selected to permit expansion of thecasing 2155 by pulling the expansion cone 2150 out of the wellbore,without having to pressurize the pressure chamber 2250.

During the radial expansion process, the pressurized areas of theapparatus 2100 are limited to the fluid passages 2160, 2165, 2170, and2175, the pressure chambers 2195 within the slips 2125, and the pressurechamber 2250. No fluid pressure acts directly on the casing 2155. Thispermits the use of operating pressures higher than the casing 2155 couldnormally withstand.

Once the casing 2155 has been completely expanded off of the expansioncone 2150, remaining portions of the apparatus 2100 are removed from thewellbore. In a preferred embodiment, the contact pressure between thedeformed thin wall sections and compressible annular members of thelower end of the existing casing and the upper end 2260 of the casing2155 ranges from about 500 to 40,000 psi in order to optimally supportthe casing 2155 using the existing wellbore casing.

In this manner, the casing 2155 is radially expanded into contact withan existing section of casing by pressurizing the interior fluidpassages 2160, 2165, 2170, and 2175 and the pressure chamber 2250 of theapparatus 2100.

In a preferred embodiment, as required, the annular body of hardenablefluidic material is then allowed to cure to form a rigid outer annularbody about the expanded casing 2155. In the case where the casing 2155is slotted, the cured fluidic material preferably permeates and envelopsthe expanded casing 2155. The resulting new section of wellbore casingincludes the expanded casing 2155 and the rigid outer annular body. Theoverlapping joint between the pre-existing wellbore casing and theexpanded casing 2155 includes the deformed thin wall sections and thecompressible outer annular bodies. The inner diameter of the resultingcombined wellbore casings is substantially constant. In this manner, amono-diameter wellbore casing is formed. This process of expandingoverlapping tubular members having thin wall end portions withcompressible annular bodies into contact can be repeated for the entirelength of a wellbore. In this manner, a mono-diameter wellbore casingcan be provided for thousands of feet in a subterranean formation.

In a preferred embodiment, as the expansion cone 2150 nears the upperend of the casing 2155, the operating flow rate of the second fluidicmaterial is reduced in order to minimize shock to the apparatus 2100. Inan alternative embodiment, the apparatus 2100 includes a shock absorberfor absorbing the shock created by the completion of the radialexpansion of the casing 2155.

In a preferred embodiment, the reduced operating pressure of the secondfluidic material ranges from about 100 to 1,000 psi as the expansioncone 2130 nears the end of the casing 2155 in order to optimally providereduced axial movement and velocity of the expansion cone 2130. In apreferred embodiment, the operating pressure of the second fluidicmaterial is reduced during the return stroke of the apparatus 2100 tothe range of about 0 to 500 psi in order minimize the resistance to themovement of the expansion cone 2130 during the return stroke. In apreferred embodiment, the stroke length of the apparatus 2100 rangesfrom about 10 to 45 feet in order to optimally provide equipment lengthsthat can be handled by conventional oil well rigging equipment whilealso minimizing the frequency at which the expansion cone 2130 must bestopped so that the apparatus 2100 can be re-stroked.

In an alternative embodiment, at least a portion of the upper sealinghead 2130 includes an expansion cone for radially expanding the casing2155 during operation of the apparatus 2100 in order to increase thesurface area of the casing 2155 acted upon during the radial expansionprocess. In this manner, the operating pressures can be reduced.

Alternatively, the apparatus 2100 may be used to join a first section ofpipeline to an existing section of pipeline. Alternatively, theapparatus 2100 may be used to directly line the interior of a wellborewith a casing, without the use of an outer annular layer of a hardenablematerial. Alternatively, the apparatus 2100 may be used to expand atubular support member in a hole.

Referring now to FIGS. 17, 17 a and 17 b, another embodiment of anapparatus 2300 for expanding a tubular member will be described. Theapparatus 2300 preferably includes a drillpipe 2305, an innerstringadapter 2310, a sealing sleeve 2315, a hydraulic slip body 2320,hydraulic slips 2325, an inner sealing mandrel 2330, an upper sealinghead 2335, a lower sealing head 2340, a load mandrel 2345, an outersealing mandrel 2350, an expansion cone 2355, a mechanical slip body2360, mechanical slips 2365, drag blocks 2370, casing 2375, fluidpassages 2380, 2385, 2390, 2395, 2400, 2405, 2410, 2415, and 2485, andmandrel launcher 2480.

The drillpipe 2305 is coupled to the innerstring adapter 2310. Duringoperation of the apparatus 2300, the drillpipe 2305 supports theapparatus 2300. The drillpipe 2305 preferably comprises a substantiallyhollow tubular member or members. The drillpipe 2305 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, oilfield country tubular goods, low alloy steel, carbonsteel, stainless steel or other similar high strength materials. In apreferred embodiment, the drillpipe 2305 is fabricated from coiledtubing in order to faciliate the placement of the apparatus 2300 innon-vertical wellbores. The drillpipe 2306 may be coupled to theinnerstring adapter 2310 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, or a standard threaded connection. In a preferredembodiment, the drillpipe 2305 is removably coupled to the innerstringadapter 2310 by a drillpipe connection.

The drillpipe 2305 preferably includes a fluid passage 2380 that isadapted to convey fluidic materials from a surface location into thefluid passage 2385. In a preferred embodiment, the fluid passage 2380 isadapted to convey fluidic materials such as, for example, cement, water,epoxy, drilling muds, or lubricants at operating pressures and flowrates ranging from about 0 to 9,000 psi and 0 to 5,000 gallons/minute inorder to optimally provide operational efficiency.

The innerstring adapter 2310 is coupled to the drill string 2305 and thesealing sleeve 2315. The innerstring adapter 2310 preferably comprises asubstantially hollow tubular member or members. The innerstring adapter2310 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the innerstringadapter 2310 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The innerstring adapter 2310 may be coupled to the drill string 2305using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, or a standard threadedconnection. In a preferred embodiment, the innerstring adapter 2310 isremovably coupled to the drill pipe 2305 by a drillpipe connection. Theinnerstring adapter 2310 may be coupled to the sealing sleeve 2315 usingany number of conventional commercially available mechanical couplingssuch as, for example, a drillpipe connection, oilfield country tubulargoods specialty threaded connection, or a standard threaded connection.In a preferred embodiment, the innerstring adapter 2310 is removablycoupled to the sealing sleeve 2315 by a standard threaded connection.

The innerstring adapter 2310 preferably includes a fluid passage 2385that is adapted to convey fluidic materials from the fluid passage 2380into the fluid passage 2390. In a preferred embodiment, the fluidpassage 2385 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud, drilling gases orlubricants at operating pressures and flow rates ranging from about 0 to9,000 psi and 0 to 3,000 gallons/minute.

The sealing sleeve 2315 is coupled to the innerstring adapter 2310 andthe hydraulic slip body 2320. The sealing sleeve 2315 preferablycomprises a substantially hollow tubular member or members. The sealingsleeve 2315 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the sealingsleeve 2315 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low-friction surfaces.

The sealing sleeve 2315 may be coupled to the innerstring adapter 2310using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connections, oilfield countrytubular goods specialty threaded connections, or a standard threadedconnection. In a preferred embodiment, the sealing sleeve 2315 isremovably coupled to the innerstring adapter 2310 by a standard threadedconnection. The sealing-sleeve 2315 may be coupled to the hydraulic slipbody 2320 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection,oilfield country tubular goods specialty threaded connection, or astandard threaded connection. In a preferred embodiment, the sealingsleeve 2315 is removably coupled to the hydraulic slip body 2320 by astandard threaded connection.

The sealing sleeve 2315 preferably includes a fluid passage 2390 that isadapted to convey fluidic materials from the fluid passage 2385 into thefluid passage 2395. In a preferred embodiment, the fluid passage 2315 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The hydraulic slip body 2320 is coupled to the sealing sleeve 2315, thehydraulic slips 2325, and the inner sealing mandrel 2330. The hydraulicslip body 2320 preferably comprises a substantially hollow tubularmember or members. The hydraulic slip body 2320 may be fabricated fromany number of conventional commercially available materials such as, forexample, oilfield country tubular goods, low alloy steel, carbon steel,stainless steel or other high strength material. In a preferredembodiment, the hydraulic slip body 2320 is fabricated from carbon steelin order to optimally provide high strength at low cost.

The hydraulic slip body 2320 may be coupled to the sealing sleeve 2315using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, or a standard threadedconnection. In a preferred embodiment, the hydraulic slip body 2320 isremovably coupled to the sealing sleeve 2315 by a standard threadedconnection. The hydraulic slip body 2320 may be coupled to the slips2325 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, thehydraulic slip body 2320 is removably coupled to the slips 2326 by astandard threaded connection. The hydraulic slip body 2320 may becoupled to the inner sealing mandrel 2330 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtythreaded connection, welding, amorphous bonding or a standard threadedconnection. In a preferred embodiment, the hydraulic slip body 2320 isremovably coupled to the inner sealing mandrel 2330 by a standardthreaded connection.

The hydraulic slips body 2320 preferably includes a fluid passage 2395that is adapted to convey fluidic materials from the fluid passage 2390into the fluid passage 2405. In a preferred embodiment, the fluidpassage 2395 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The hydraulic slips body 2320 preferably includes fluid passage 2400that are adapted to convey fluidic materials from the fluid passage 2395into the pressure chambers 2420 of the hydraulic slips 2325. In thismanner, the slips 2325 are activated upon the pressurization of thefluid passage 2395 into contact with the inside surface of the casing2375. In a preferred embodiment, the fluid passages 2400 are adapted toconvey fluidic materials such as, for example, water, drilling mud orlubricants at operating pressures and flow rates ranging from about 0 to9,000 psi and 0 to 3,000 gallons/minute.

The slips 2325 are coupled to the outside surface of the hydraulic slipbody 2320. During operation of the apparatus 2300, the slips 2325 areactivated upon the pressurization of the fluid passage 2395 into contactwith the inside surface of the casing 2375. In this manner, the slips2325 maintain the casing 2375 in a substantially stationary position.

The slips 2325 preferably include the fluid passages 2400, the pressurechambers 2420, spring bias 2426, and slip members 2430. The slips 2325may comprise any number of conventional commercially available hydraulicslips such as, for example, RTTS packer tungsten carbide hydraulic slipsor Model 3L retrievable bridge plug with hydraulic slips. In a preferredembodiment, the slips 2325 comprise RTTS packer tungsten carbidehydraulic slips available from Halliburton Energy Services in order tooptimally provide resistance to axial movement of the casing 2375 duringthe radial expansion process.

The inner sealing mandrel 2330 is coupled to the hydraulic slip body2320 and the lower sealing head 2340. The inner sealing mandrel 2330preferably comprises a substantially hollow tubular member or members.The inner sealing mandrel 2330 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the inner sealing mandrel 2330 is fabricated from stainlesssteel in order to optimally provide high strength, corrosion resistance,and low friction surfaces.

The inner sealing mandrel 2330 may be coupled to the hydraulic slip body2320 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, the innersealing mandrel 2330 is removably coupled to the hydraulic slip body2320 by a standard threaded connection. The inner sealing mandrel 2330may be coupled to the lower sealing head 2340 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtythreaded connection, welding, amorphous bonding, or a standard threadedconnection. In a preferred embodiment, the inner sealing mandrel 2330 isremovably coupled to the lower sealing head 2340 by a standard threadedconnection.

The inner sealing mandrel 2330 preferably includes a fluid passage 2405that is adapted to convey fluidic materials from the fluid passage 2395into the fluid passage 2415. In a preferred embodiment, the fluidpassage 2405 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The upper sealing head 2335 is coupled to the outer sealing mandrel 2345and expansion cone 2355. The upper sealing head 2335 is also movablycoupled to the outer surface of the inner sealing mandrel 2330 and theinner surface of the casing 2375. In this manner, the upper sealing head2335 reciprocates in the axial direction. The radial clearance betweenthe inner cylindrical surface of the upper sealing head 2335 and theouter surface of the inner sealing mandrel 2330 may range, for example,from about 0.0025 to 0.05 inches. In a preferred embodiment, the radialclearance between the inner cylindrical surface of the upper sealinghead 2335 and the outer surface of the inner sealing mandrel 2380 rangesfrom about 0.005 to 0.01 inches in order to optimally provide minimalclearance. The radial clearance between the outer cylindrical surface ofthe upper sealing head 2335 and the inner surface of the casing 2375 mayrange, for example, from about 0.025 to 0.375 inches. In a preferredembodiment, the radial clearance between the outer cylindrical surfaceof the upper sealing head 2335 and the inner surface of the casing 2375ranges from about 0.025 to 0.125 inches in order to optimally providestabilization for the expansion cone 2355 during the expansion process.

The upper sealing head 2335 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The uppersealing head 2335 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the uppersealing head 2335 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces. The inner surface of the upper sealing head 2335 preferablyincludes one or more annular sealing members 2435 for sealing theinterface between the upper sealing head 2335 and the inner sealingmandrel 2330. The sealing members 2435 may comprise any number ofconventional commercially available annular sealing members such as, forexample, o-rings, polypak seals or metal spring energized seals. In apreferred embodiment, the sealing members 2435 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

In a preferred embodiment, the upper sealing head 2335 includes ashoulder 2440 for supporting the upper sealing head on the lower sealinghead 1930.

The upper sealing head 2335 may be coupled to the outer sealing mandrel2350 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, the uppersealing head 2335 is removably coupled to the outer sealing mandrel 2350by a standard threaded connection. In a preferred embodiment, themechanical coupling between the upper sealing head 2335 and the outersealing mandrel 2350 includes one or more sealing members 2445 forfluidicly sealing the interface between the upper sealing head 2335 andthe outer sealing mandrel 2350. The sealing members 2445 may compriseany number of conventional commercially available sealing members suchas, for example, o-rings, polypak seals or metal spring energized seals.In a preferred embodiment, the sealing members 2445 comprise polypakseals available from Parker Seals in order to optimally provide sealingfor long axial strokes.

The lower sealing head 2340 is coupled to the inner sealing mandrel 2330and the load mandrel 2345. The lower sealing head 2340 is also movablycoupled to the inner surface of the outer sealing mandrel 2350. In thismanner, the upper sealing head 2335 and outer sealing mandrel 2350reciprocate in the axial direction. The radial clearance between theouter surface of the lower sealing head 2340 and the inner surface ofthe outer sealing mandrel 2350 may range, for example, from about 0.0025to 0.05 inches. In a preferred embodiment, the radial clearance betweenthe outer surface of the lower sealing head 2340 and the inner surfaceof the outer sealing mandrel 2350 ranges from about 0.005 to 0.010inches in order to optimally provide minimal radial clearance.

The lower sealing head 2340 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The lowersealing head 2340 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield tubularmembers, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the lower sealinghead 2340 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.The outer surface of the lower sealing head 2340 preferably includes oneor more annular sealing members 2450 for sealing the interface betweenthe lower sealing head 2340 and the outer sealing mandrel 2350. Thesealing members 2450 may comprise any number of conventionalcommercially available annular sealing members such as, for example,o-rings, polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 2450 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for a long axialstroke.

The lower sealing head 2340 may be coupled to the inner sealing mandrel2330 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular specialty threaded connection, welding, amorphous bonding, orstandard threaded connection. In a preferred embodiment, the lowersealing head 2340 is removably coupled to the inner sealing mandrel 2330by a standard threaded connection. In a preferred embodiment, themechanical coupling between the lower sealing head 2340 and the innersealing mandrel 2330 includes one or more sealing members 2455 forfluidicly sealing the interface between the lower sealing head 2340 andthe inner sealing mandrel 2330. The sealing members 2455 may compriseany number of conventional commercially available sealing members suchas, for example, o-rings, polypak or metal spring energized seals. In apreferred embodiment, the sealing members 2455 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke length.

The lower sealing head 2340 may be coupled to the load mandrel 2345using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, the lowersealing head 2340 is removably coupled to the load mandrel 2345 by astandard threaded connection. In a preferred embodiment, the mechanicalcoupling between the lower sealing head 2340 and the load mandrel 2345includes one or more sealing members 2460 for fluidicly sealing theinterface between the lower sealing head 2340 and the load mandrel 2345.The sealing members 2460 may comprise any number of conventionalcommercially available sealing members such as, for example, o-rings,polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 2460 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for a long axialstroke length.

In a preferred embodiment, the lower sealing head 2340 includes a throatpassage 2465 fluidicly coupled between the fluid passages 2405 and 2415.The throat passage 2465 is preferably of reduced size and is adapted toreceive and engage with a plug 2470, or other similar device. In thismanner, the fluid passage 2405 is fluidicly isolated from the fluidpassage 2415. In this manner, the pressure chamber 2475 is pressurized.

The outer sealing mandrel 2350 is coupled to the upper sealing head 2335and the expansion cone 2355. The outer sealing mandrel 2350 is alsomovably coupled to the inner surface of the casing 2375 and the outersurface of the lower sealing head 2340. In this manner, the uppersealing head 2335, outer sealing mandrel 2350, and the expansion cone2355 reciprocate in the axial direction. The radial clearance betweenthe outer surface of the outer sealing mandrel 2350 and the innersurface of the casing 2375 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer surface of the outer sealing mandrel 2350 and the innersurface of the casing 2375 ranges from about 0.025 to 0.125 inches inorder to optimally provide stabilization for the expansion cone 2355during the expansion process. The radial clearance between the innersurface of the outer sealing mandrel 2350 and the outer surface of thelower sealing head 2340 may range, for example, from about 0.0025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe inner surface of the outer sealing mandrel 2350 and the outersurface of the lower sealing head 2340 ranges from about 0.005 to 0.010inches in order to optimally provide minimal clearance.

The outer sealing mandrel 2350 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The outersealing mandrel 2350 may be fabricated from any number of conventionalcommercially available materials such as, for example, low alloy steel,carbon steel, stainless steel or other similar high strength materials.In a preferred embodiment, the outer sealing mandrel 2350 is fabricatedfrom stainless steel in order to optimally provide high strength,corrosion resistance, and low friction surfaces.

The outer sealing mandrel 2350 may be coupled to the upper sealing head2335 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connections, oilfield countrytubular goods specialty threaded connections, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the outer sealing mandrel 2350 is removably coupled to the upper sealinghead 2335 by a standard threaded connection. The outer sealing mandrel2350 may be coupled to the expansion cone 2355 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtythreaded connection, welding, amorphous bonding, or a standard threadedconnection. In a preferred embodiment, the outer sealing mandrel 2350 isremovably coupled to the expansion cone 2355 by a standard threadedconnection.

The upper sealing head 2335, the lower sealing head 2340, the innersealing mandrel 2330, and the outer sealing mandrel 2350 together definea pressure chamber 2475. The pressure chamber 2475 is fluidicly coupledto the passage 2405 via one or more passages 2410. During operation ofthe apparatus 2300, the plug 2470 engages with the throat passage 2465to fluidicly isolate the fluid passage 2415 from the fluid passage 2405.The pressure chamber 2475 is then pressurized which in turn causes theupper sealing head 2335, outer sealing mandrel 2350, and expansion cone2355 to reciprocate in the axial direction. The axial motion of theexpansion cone 2355 in turn expands the casing 2375 in the radialdirection.

The load mandrel 2345 is coupled to the lower sealing head 2340 and themechanical slip body 2360. The load mandrel 2345 preferably comprises anannular member having substantially cylindrical inner and outersurfaces. The load mandrel 2345 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the load mandrel 2345 is fabricated from stainless steel inorder to optimally provide high strength, corrosion resistance, and lowfriction surfaces.

The load mandrel 2345 may be coupled to the lower sealing head 2340using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, the loadmandrel 2345 is removably coupled to the lower sealing head 2340 by astandard threaded connection. The load mandrel 2345 may be coupled tothe mechanical slip body 2360 using any number of conventionalcommercially available mechanical couplings such as, for example,drillpipe connection, oilfield country tubular goods specialty threadedconnection, welding, amorphous bonding, or a standard threadedconnection. In a preferred embodiment, the load mandrel 2345 isremovably coupled to the mechanical slip body 2360 by a standardthreaded connection.

The load mandrel 2345 preferably includes a fluid passage 2415 that isadapted to convey fluidic materials from the fluid passage 2405 to theregion outside of the apparatus 2300. In a preferred embodiment, thefluid passage 2415 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The expansion cone 2355 is coupled to the outer sealing mandrel 2350.The expansion cone 2355 is also movably coupled to the inner surface ofthe casing 2375. In this manner, the upper sealing head 2335, outersealing mandrel 2350, and the expansion cone 2355 reciprocate in theaxial direction. The reciprocation of the expansion cone 2355 causes thecasing 2375 to expand in the radial direction.

The expansion cone 2355 preferably comprises an annular member havingsubstantially cylindrical inner and conical outer surfaces. The outsideradius of the outside conical surface may range, for example, from about2 to 34 inches. In a preferred embodiment, the outside radius of theoutside conical surface ranges from about 3 to 28 inches in order tooptimally provide radial expansion of the typical casings. The axiallength of the expansion cone 2355 may range, for example, from about 2to 8 times the largest outside diameter of the expansion cone 2355. In apreferred embodiment, the axial length of the expansion cone 2355 rangesfrom about 3 to 5 times the largest outside diameter of the expansioncone 2355 in order to optimally provide stability and centralization ofthe expansion cone 2355 during the expansion process. In a preferredembodiment, the angle of attack of the expansion cone 2355 ranges fromabout 5 to 3 degrees in order to optimally frictional forces with radialexpansion forces. The optimum angle of attack of the expansion cone 2355will vary as a function of the operating parameters of the particularexpansion operation.

The expansion cone 2355 may be fabricated from any number ofconventional commercially available materials such as, for example,machine tool steel, nitride steel, titanium, tungsten carbide, ceramicsor other similar high strength materials. In a preferred embodiment, theexpansion cone 2355 is fabricated from D2 machine tool steel in order tooptimally provide high strength, abrasion resistance, and gallingresistance. In a particularly preferred embodiment, the outside surfaceof the expansion cone 2355 has a surface hardness ranging from about 58to 62 Rockwell C in order to optimally provide high strength, abrasionresistance, resistance to galling.

The expansion cone 2355 may be coupled to the outside sealing mandrel2350 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, theexpansion cone 2355 is coupled to the outside sealing mandrel 2350 usinga standard threaded connection in order to optimally provide highstrength and permit the expansion cone 2355 to be easily replaced.

The mandrel launcher 2480 is coupled to the casing 2375. The mandrellauncher 2480 comprises a tubular section of casing having a reducedwall thickness compared to the casing 2375. In a preferred embodiment,the wall thickness of the mandrel launcher 2480 is about 50 to 100% ofthe wall thickness of the casing 2375. In this manner, the initiation ofthe radial expansion of the casing 2375 is facilitated, and theplacement of the apparatus 2300 into a wellbore casing and wellbore isfacilitated.

The mandrel launcher 2480 may be coupled to the casing 2375 using anynumber of conventional mechanical couplings. The mandrel launcher 2480may have a wall thickness ranging, for example, from about 0.15 to 1.5inches. In a preferred embodiment, the wall thickness of the mandrellauncher 2480 ranges from about 0.25 to 0.75 inches in order tooptimally provide high strength in a minimal profile. The mandrellauncher 2480 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the mandrel launcher2480 is fabricated from oilfield tubular goods having a higher strengththan that of the casing 2375 but with a smaller wall thickness than thecasing 2375 in order to optimally provide a thin walled container havingapproximately the same burst strength as that of the casing 2375.

The mechanical slip body 2460 is coupled to the load mandrel 2345, themechanical slips 2365, and the drag blocks 2370. The mechanical slipbody 2460 preferably comprises a tubular member having an inner passage2485 fluidicly coupled to the passage 2415. In this manner, fluidicmaterials may be conveyed from the passage 2484 to a region outside ofthe apparatus 2300.

The mechanical slip body 2360 may be coupled to the load mandrel 2345using any number of conventional mechanical couplings. In a preferredembodiment, the mechanical slip body 2360 is removably coupled to theload mandrel 2345 using threads and sliding steel retaining rings inorder to optimally provide a high strength attachment. The mechanicalslip body 2360 may be coupled to the mechanical slips 2365 using anynumber of conventional mechanical couplings. In a preferred embodiment,the mechanical slip body 2360 is removably coupled to the mechanicalslips 2365 using threads and sliding steel retaining rings in order tooptimally provide a high strength attachment. The mechanical slip body2360 may be coupled to the drag blocks 2370 using any number ofconventional mechanical couplings. In a preferred embodiment, themechanical slip body 2360 is removably coupled to the drag blocks 2365using threads and sliding steel retaining rings in order to optimallyprovide a high strength attachment.

The mechanical slips 2365 are coupled to the outside surface of themechanical slip body 2360. During operation of the apparatus 2300, themechanical slips 2365 prevent upward movement of the casing 2375 andmandrel launcher 2480. In this manner, during the axial reciprocation ofthe expansion cone 2355, the casing 2375 and mandrel launcher 2480 aremaintained in a substantially stationary position. In this manner, themandrel launcher 2480 and casing 2375 are expanded in the radialdirection by the axial movement of the expansion cone 2355.

The mechanical slips 2365 may comprise any number of conventionalcommercially available mechanical slips such as, for example, RTTSpacker tungsten carbide mechanical slips, RTTS packer wicker typemechanical slips or Model 3L retrievable bridge plug tungsten carbideupper mechanical slips. In a preferred embodiment, the mechanical slips2365 comprise RTTS packer tungsten carbide mechanical slips availablefrom Halliburton Energy Services in order to optimally provideresistance to axial movement of the casing 2375 during the expansionprocess.

The drag blocks 2370 are coupled to the outside surface of themechanical slip body 2360. During operation of the apparatus 2300, thedrag blocks 2370 prevent upward movement of the casing 2375 and mandrellauncher 2480. In this manner, during the axial reciprocation of theexpansion cone 2355, the casing 2375 and mandrel launcher 2480 aremaintained in a substantially stationary position. In this manner, themandrel launcher 2480 and casing 2375 are expanded in the radialdirection by the axial movement of the expansion cone 2355.

The drag blocks 2370 may comprise any number of conventionalcommercially available mechanical slips such as, for example, RTTSpacker mechanical drag blocks or Model 3L retrievable bridge plug dragblocks. In a preferred embodiment, the drag blocks 2370 comprise RTTSpacker mechanical drag blocks available from Halliburton Energy Servicesin order to optimally provide resistance to axial movement of the casing2375 during the expansion process.

The casing 2375 is coupled to the mandrel launcher 2480. The casing 2375is further removably coupled to the mechanical slips 2365 and dragblocks 2370. The casing 2375 preferably comprises a tubular member. Thecasing 2375 may be fabricated from any number of conventionalcommercially available materials such as, for example, slotted tubulars,oil country tubular goods, carbon steel, low alloy steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the casing 2375 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide high strength. In a preferred embodiment, the upperend of the casing 2375 includes one or more sealing members positionedabout the exterior of the casing 2375.

During operation, the apparatus 2300 is positioned in a wellbore withthe upper end of the casing 2375 positioned in an overlappingrelationship within an existing wellbore casing. In order minimize surgepressures within the borehole during placement of the apparatus 2300,the fluid passage 2380 is preferably provided with one or more pressurerelief passages. During the placement of the apparatus 2300 in thewellbore, the casing 2375 is supported by the expansion cone 2355.

After positioning of the apparatus 2300 within the bore hole in anoverlapping relationship with an existing section of wellbore casing, afirst fluidic material is pumped into the fluid passage 2380 from asurface location. The first fluidic material is conveyed from the fluidpassage 2380 to the fluid passages 2385, 2390, 2395, 2405, 2415, and2485. The first fluidic material will then exit the apparatus 2300 andfill the annular region between the outside of the apparatus 2300 andthe interior walls of the bore hole.

The first fluidic material may comprise any number of conventionalcommercially available materials such as, for example, epoxy, drillingmud, slag mix, cement, or water. In a preferred embodiment, the firstfluidic material comprises a hardenable fluidic sealing material suchas, for example, slag mix, epoxy, or cement. In this manner, a wellborecasing having an outer annular layer of a hardenable material may beformed.

The first fluidic material may be pumped into the apparatus 2300 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi, and 0 to 3,000 gallons/minute. In a preferred embodiment, thefirst fluidic material is pumped into the apparatus 2300 at operatingpressures and flow rates ranging from about 0 to 3,500 psi and 0 to1,200 gallons/minute in order to optimally provide operationalefficiency.

At a predetermined point in the injection of the first fluidic materialsuch as, for example, after the annular region outside of the apparatus2300 has been filled to a predetermined level, a plug 2470, dart, orother similar device is introduced into the first fluidic material. Theplug 2470 lodges in the throat passage 2465 thereby fluidicly isolatingthe fluid passage 2405 from the fluid passage 2415.

After placement of the plug 2470 in the throat passage 2465, a secondfluidic material is pumped into the fluid passage 2380 in order topressurize the pressure chamber 2475. The second fluidic material maycomprise any number of conventional commercially available materialssuch as, for example, water, drilling gases, drilling mud or lubricants.In a preferred embodiment, the second fluidic material comprises anon-hardenable fluidic material such as, for example, water, drillingmud or lubricant.

The second fluidic material may be pumped into the apparatus 2300 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thesecond fluidic material is pumped into the apparatus 2300 at operatingpressures and flow rates ranging from about 0 to 3,500 psi and 0 to1,200 gallons/minute in order to optimally provide operationalefficiency.

The pressurization of the pressure chamber 2475 causes the upper sealinghead 2335, outer sealing mandrel 2350, and expansion cone 2355 to movein an axial direction. The pressurization of the pressure chamber 2475also causes the hydraulic slips 2325 to expand in the radial directionand hold the casing 2375 in a substantially stationary position.Furthermore, as the expansion cone 2355 moves in the axial direction,the expansion cone 2355 pulls the mandrel launcher 2480 and drag blocks2370 along, which sets the mechanical slips 2365 and stops further axialmovement of the mandrel launcher 2480 and casing 2375. In this manner,the axial movement of the expansion cone 2355 radially expands themandrel launcher 2480 and casing 2375.

Once the upper sealing head 2335, outer sealing mandrel 2350, andexpansion cone 2355 complete an axial stroke, the operating pressure ofthe second fluidic material is reduced. The reduction in the operatingpressure of the second fluidic material releases the hydraulic slips2325. The drill string 2305 is then raised. This causes the innersealing mandrel 2330, lower sealing head 2340, load mandrel 2345, andmechanical slip body 2360 to move upward. This unsets the mechanicalslips 2365 and permits the mechanical slips 2365 and drag blocks 2370 tobe moved within the mandrel launcher 2480 and casing 2375. When thelower sealing head 2340 contacts the upper sealing head 2335, the secondfluidic material is again pressurized and the radial expansion processcontinues. In this manner, the mandrel launcher 2480 and casing 2375 areradial expanded through repeated axial strokes of the upper sealing head2335, outer sealing mandrel 2350 and expansion cone 2355. Throughput theradial expansion process, the upper end of the casing 2375 is preferablymaintained in an overlapping relation with an existing section ofwellbore casing.

At the end of the radial expansion process, the upper end of the casing2375 is expanded into intimate contact with the inside surface of thelower end of the existing wellbore casing. In a preferred embodiment,the sealing members provided at the upper end of the casing 2375 providea fluidic seal between the outside surface of the upper end of thecasing 2375 and the inside surface of the lower end of the existingwellbore casing. In a preferred embodiment, the contact pressure betweenthe casing 2375 and the existing section of wellbore casing ranges fromabout 400 to 10,000 psi in order to optimally provide contact pressure,activate the sealing members, and withstand typical tensile andcompressive loading conditions.

In a preferred embodiment, as the expansion cone 2355 nears the upperend of the casing 2375, the operating pressure of the second fluidicmaterial is reduced in order to minimize shock to the apparatus 2300. Inan alternative embodiment, the apparatus 2300 includes a shock absorberfor absorbing the shock created by the completion of the radialexpansion of the casing 2375.

In a preferred embodiment, the reduced operating pressure of the secondfluidic material ranges from about 100 to 1,000 psi as the expansioncone 2355 nears the end of the casing 2375 in order to optimally providereduced axial movement and velocity of the expansion cone 2355. In apreferred embodiment, the operating pressure of the second fluidicmaterial is reduced during the return stroke of the apparatus 2300 tothe range of about 0 to 500 psi in order minimize the resistance to themovement of the expansion cone 2355 during the return stroke. In apreferred embodiment, the stroke length of the apparatus 2300 rangesfrom about 10 to 45 feet in order to optimally provide equipment thatcan be handled by typical oil well rigging equipment and minimize thefrequency at which the expansion cone 2355 must be stopped to permit theapparatus 2300 to be re-stroked.

In an alternative embodiment, at least a portion of the upper sealinghead 2335 includes an expansion cone for radially expanding the mandrellauncher 2480 and casing 2375 during operation of the apparatus 2300 inorder to increase the surface area of the casing 2375 acted upon duringthe radial expansion process. In this manner, the operating pressurescan be reduced.

In an alternative embodiment, mechanical slips 2365 are positioned in anaxial location between the sealing sleeve 2315 and the inner sealingmandrel 2330 in order to optimally the construction and operation of theapparatus 2300.

Upon the complete radial expansion of the casing 2375, if applicable,the first fluidic material is permitted to cure within the annularregion between the outside of the expanded casing 2375 and the interiorwalls of the wellbore. In the case where the casing 2375 is slotted, thecured fluidic material preferably permeates and envelops the expandedcasing 2375. In this manner, a new section of wellbore casing is formedwithin a wellbore. Alternatively, the apparatus 2300 may be used to joina first section of pipeline to an existing section of pipeline.Alternatively, the apparatus 2300 may be used to directly line theinterior of a wellbore with a casing, without the use of an outerannular layer of a hardenable material. Alternatively, the apparatus2300 may be used to expand a tubular support member in a hole.

During the radial expansion process, the pressurized areas of theapparatus 2300 are limited to the fluid passages 2380, 2385, 2390, 2395,2400, 2405, and 2410, and the pressure chamber 2475. No fluid pressureacts directly on the mandrel launcher 2480 and casing 2375. This permitsthe use of operating pressures higher than the mandrel launcher 2480 andcasing 2375 could normally withstand.

Referring now to FIG. 18, a preferred embodiment of an apparatus 2500for forming a mono-diameter wellbore casing will be described. Theapparatus 2500 preferably includes a drillpipe 2505, an innerstringadapter 2510, a sealing sleeve 2515, a hydraulic slip body 2520,hydraulic slips 2525, an inner sealing mandrel 2530, upper sealing head2535, lower sealing head 2540, outer sealing mandrel 2545, load mandrel2550, expansion cone 2555, casing 2560, and fluid passages 2565, 2570,2575, 2580, 2585, 2590, 2595, and 2600.

The drillpipe 2505 is coupled to the innerstring adapter 2510. Duringoperation of the apparatus 2500, the drillpipe 2505 supports theapparatus 2500. The drillpipe 2505 preferably comprises, a substantiallyhollow tubular member or members. The drillpipe 2505 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, oilfield country tubular goods, low alloy steel, carbonsteel, stainless steel or other similar high strength materials. In apreferred embodiment, the drillpipe 2505 is fabricated from coiledtubing in order to faciliate the placement of the apparatus 2500 innon-vertical wellbores. The drillpipe 2505 may be coupled to theinnerstring adapter 2510 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, or a standard threaded connection. In a preferredembodiment, the drillpipe 2505 is removably coupled to the innerstringadapter 2510 by a drillpipe connection. a drillpipe connection providesthe advantages of high strength and easy disassembly.

The drillpipe 2505 preferably includes a fluid passage 2565 that isadapted to convey fluidic materials from a surface location into thefluid passage 2570. In a preferred embodiment, the fluid passage 2565 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud, or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The innerstring adapter 2510 is coupled to the drill string 2505 and thesealing sleeve 2515. The innerstring adapter 2510 preferably comprises asubstantially hollow tubular member or members. The innerstring adapter2510 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the innerstringadapter 2510 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The innerstring adapter 2510 may be coupled to the drill string 2505using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnection. In a preferred embodiment, the innerstring adapter 2510 isremovably coupled to the drill pipe 2505 by a drillpipe connection. Theinnerstring adapter 2510 may be coupled to the sealing sleeve 2515 usingany number of conventional commercially available mechanical couplingssuch as, for example, drillpipe connection, oilfield country tubulargoods specialty type threaded connection, ratchet-latch type threadedconnection or a standard threaded connection. In a preferred embodiment,the innerstring adapter 2510 is removably coupled to the sealing sleeve2515 by a standard threaded connection.

The innerstring adapter 2510 preferably includes a fluid passage 2570that is adapted to convey fluidic materials from the fluid passage 2565into the fluid passage 2575. In a preferred embodiment, the fluidpassage 2570 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The sealing sleeve 2515 is coupled to the innerstring adapter 2510 andthe hydraulic slip body 2520. The sealing sleeve 2515 preferablycomprises a substantially hollow tubular member or members. The sealingsleeve 2515 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the sealingsleeve 2515 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low-friction surfaces.

The sealing sleeve 2515 may be coupled to the innerstring adapter 2510using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connections, oilfield countrytubular goods specialty type threaded connection, ratchet-latch typethreaded connection, or a standard threaded connection. In a preferredembodiment, the sealing sleeve 2515 is removably coupled to theinnerstring adapter 2510 by a standard threaded connection. The sealingsleeve 2515 may be coupled to the hydraulic slip body 2520 using anynumber of conventional commercially available mechanical couplings suchas, for example, drillpipe connection, oilfield country tubular goodsspecialty type threaded connection, ratchet-latch type threadedconnection, or a standard threaded connection. In a preferredembodiment, the sealing sleeve 2515 is removably coupled to thehydraulic slip body 2520 by a standard threaded connection.

The sealing sleeve 2515 preferably includes a fluid passage 2575 that isadapted to convey fluidic materials from the fluid passage 2570 into thefluid passage 2580. In a preferred embodiment, the fluid passage 2575 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The hydraulic slip body 2520 is coupled to the sealing sleeve 2515, thehydraulic slips 2525, and the inner sealing mandrel 2530. The hydraulicslip body 2520 preferably comprises a substantially hollow tubularmember or members. The hydraulic slip body 2520 may be fabricated fromany number of conventional commercially available materials such as, forexample, oilfield country tubular goods, low alloy steel, carbon steel,stainless steel or other similar high strength materials. In a preferredembodiment, the hydraulic slip body 2520 is fabricated from carbon steelin order to optimally provide high strength.

The hydraulic slip body 2520 may be coupled to the sealing sleeve 2515using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, ratchet-latch typethreaded connection or a standard threaded connection. In a preferredembodiment, the hydraulic slip body 2520 is removably coupled to thesealing sleeve 2515 by a standard threaded connection. The hydraulicslip body 2520 may be coupled to the slips 2525 using any number ofconventional commercially available mechanical couplings such as, forexample, threaded connection or welding. In a preferred embodiment, thehydraulic slip body 2520 is removably coupled to the slips 2525 by athreaded connection. The hydraulic slip body 2520 may be coupled to theinner sealing mandrel 2580 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, welding, amorphous bonding or a standard threadedconnection. In a preferred embodiment, the hydraulic slip body 2520 isremovably coupled to the inner sealing mandrel 2530 by a standardthreaded connection.

The hydraulic slips body 2520 preferably includes a fluid passage 2580that is adapted to convey fluidic materials from the fluid passage 2575into the fluid passage 2590. In a preferred embodiment, the fluidpassage 2580 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The hydraulic slips body 2520 preferably includes fluid passages 2585that are adapted to convey fluidic materials from the fluid passage 2580into the pressure chambers of the hydraulic slips 2525. In this manner,the slips 2525 are activated upon the pressurization of the fluidpassage 2580 into contact with the inside surface of the casing 2560. Ina preferred embodiment, the fluid passages 2585 are adapted to conveyfluidic materials such as, for example, water, drilling mud orlubricants at operating pressures and flow rates ranging from about 0 to9,000 psi and 0 to 3,000 gallons/minute.

The slips 2525 are coupled to the outside surface of the hydraulic slipbody 2520. During operation of the apparatus 2500, the slips 2525 areactivated upon the pressurization of the fluid passage 2580 into contactwith the inside surface of the casing 2560. In this manner, the slips2525 maintain the casing 2560 in a substantially stationary position.

The slips 2525 preferably include the fluid passages 2585, the pressurechambers 2605, spring bias 2610, and slip members 2615. The slips 2525may comprise any number of conventional commercially available hydraulicslips such as, for example, RTTS packer tungsten carbide hydraulic slipsor Model 3L retrievable bridge plug with hydraulic slips. In a preferredembodiment, the slips 2525 comprise RTTS packer tungsten carbidehydraulic slips available from Halliburton Energy Services in order tooptimally provide resistance to axial movement of the casing 2560 duringthe expansion process.

The inner sealing mandrel 2530 is coupled to the hydraulic slip body2520 and the lower sealing head 2540. The inner sealing mandrel 2530preferably comprises a substantially hollow tubular member or members.The inner sealing mandrel 2530 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the inner sealing mandrel 2530 is fabricated from stainlesssteel in order to optimally provide high strength, corrosion resistance,and low friction surfaces.

The inner sealing mandrel 2530 may be coupled to the hydraulic slip body2520 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the inner sealing mandrel 2530 is removably coupled to the hydraulicslip body 2520 by a standard threaded connection. The inner sealingmandrel 2530 may be coupled to the lower sealing head 2540 using anynumber of conventional commercially available mechanical couplings suchas, for example, oilfield country tubular goods specialty type threadedconnection, drillpipe connection, welding, amorphous bonding, or astandard threaded connection. In a preferred embodiment, the innersealing mandrel 2530 is removably coupled to the lower sealing head 2540by a standard threaded connection.

The inner sealing mandrel 2530 preferably includes a fluid passage 2590that is adapted to convey fluidic materials from the fluid passage 2580into the fluid passage 2600. In a preferred embodiment, the fluidpassage 2590 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The upper sealing head 2535 is coupled to the outer sealing mandrel 2545and expansion cone 2555. The upper sealing head 2535 is also movablycoupled to the outer surface of the inner sealing mandrel 2530 and theinner surface of the casing 2560. In this manner, the upper sealing head2535 reciprocates in the axial direction. The radial clearance betweenthe inner cylindrical surface of the upper sealing head 2535 and theouter surface of the inner sealing mandrel 2530 may range, for example,from about 0.0025 to 0.05 inches. In a preferred embodiment, the radialclearance between the inner cylindrical surface of the upper sealinghead 2535 and the outer surface of the inner sealing mandrel 2530 rangesfrom about 0.005 to 0.01 inches in order to optimally provide minimalradial clearance. The radial clearance between the outer cylindricalsurface of the upper sealing head 2535 and the inner surface of thecasing 2560 may range, for example, from about 0.025 to 0.375 inches. Ina preferred embodiment, the radial clearance between the outercylindrical surface of the upper sealing head 2535 and the inner surfaceof the casing 2560 ranges from about 0.025 to 0.125 inches in order tooptimally provide stabilization for the expansion cone 2535 during theexpansion process.

The upper sealing head 2535 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The uppersealing head 2535 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, ow alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the uppersealing head 2535 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces. The inner surface of the upper sealing head 2535 preferablyincludes one or more annular sealing members 2620 for sealing theinterface between the upper sealing head 2535 and the inner sealingmandrel 2530. The sealing members 2620 may comprise any number ofconventional commercially available annular sealing members such as, forexample, o-rings, polypak seals, or metal spring energized seals. In apreferred embodiment, the sealing members 2620 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

In a preferred embodiment, the upper sealing head 2535 includes ashoulder 2625 for supporting the upper sealing head 2535, outer sealingmandrel 2545, and expansion cone 2555 on the lower sealing head 2540.

The upper sealing head 2535 may be coupled to the outer sealing mandrel2545 using any number of conventional commercially available mechanicalcouplings such as, for example, oilfield country tubular goods specialtythreaded connection, pipeline connection, welding, amorphous bonding, ora standard threaded connection. In a preferred embodiment, the uppersealing head 2535 is removably coupled to the outer sealing mandrel 2545by a standard threaded connection. In a preferred embodiment, themechanical coupling between the upper sealing head 2535 and the outersealing mandrel 2545 includes one or more sealing members 2630 forfluidicly sealing the interface between the upper sealing head 2535 andthe outer sealing mandrel 2545. The sealing members 2630 may compriseany number of conventional commercially available sealing members suchas, for example, o-rings, polypak seals or metal spring energized seals.In a preferred embodiment, the sealing members 2630 comprise polypakseals available from Parker Seals in order to optimally provide sealingfor a long axial stroke.

The lower sealing head 2540 is coupled to the inner sealing mandrel 2530and the load mandrel 2550. The lower sealing head 2540 is also movablycoupled to the inner surface of the outer sealing mandrel 2545. In thismanner, the upper sealing head 2535, outer sealing mandrel 2545, andexpansion cone 2555 reciprocate in the axial direction.

The radial clearance between the outer surface of the lower sealing head2540 and the inner surface of the outer sealing mandrel 2545 may range,for example, from about 0.0025 to 0.05 inches. In a preferredembodiment, the radial clearance between the outer surface of the lowersealing head 2540 and the inner surface of the outer sealing mandrel2545 ranges from about 0.005 to 0.01 inches in order to optimallyprovide minimal radial clearance.

The lower sealing head 2540 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The lowersealing head 2540 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the lowersealing head 2540 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces. The outer surface of the lower sealing head 2540 preferablyincludes one or more annular sealing members 2635 for sealing theinterface between the lower sealing head 2540 and the outer sealingmandrel 2545. The sealing members 2635 may comprise any number ofconventional commercially available annular sealing members such as, forexample, o-rings, polypak seals, or metal spring energized seals. In apreferred embodiment, the sealing members 2635 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

The lower sealing head 2540 may be coupled to the inner sealing mandrel2530 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connections, oilfield countrytubular goods specialty threaded connection, or a standard threadedconnection. In a preferred embodiment, the lower sealing head 2540 isremovably coupled to the inner sealing mandrel 2530 by a standardthreaded connection. In a preferred embodiment, the mechanical couplingbetween the lower sealing head 2540 and the inner sealing mandrel 2530includes one or more sealing members 2640 for fluidicly sealing theinterface between the lower sealing head 2540 and the inner sealingmandrel 2530. The sealing members 2640 may comprise any number ofconventional commercially available sealing members such as, forexample, o-rings, polypak seals or metal spring energized seals. In apreferred embodiment, the sealing members 2640 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

The lower sealing head 2540 may be coupled to the load mandrel 2550using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding or a standard threaded connection. In a preferred embodiment,the lower sealing head 2540 is removably coupled to the load mandrel2550 by a standard threaded connection. In a preferred embodiment, themechanical coupling between the lower sealing head 2540 and the loadmandrel 2550 includes one or more sealing members 2645 for fluidiclysealing the interface between the lower sealing head 2540 and the loadmandrel 2550. The sealing members 2645 may comprise any number ofconventional commercially available sealing members such as, forexample, o-rings, polypak seals or metal spring energized seals. In apreferred embodiment, the sealing members 2645 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

In a preferred embodiment, the lower sealing head 2540 includes a throatpassage 2650 fluidicly coupled between the fluid passages 2590 and 2600.The throat passage 2650 is preferably of reduced size and is adapted toreceive and engage with a plug 2655, or other similar device. In thismanner, the fluid passage 2590 is fluidicly isolated from the fluidpassage 2600. In this manner, the pressure chamber 2660 is pressurized.

The outer sealing mandrel 2545 is coupled to the upper sealing head 2535and the expansion cone 2555. The outer sealing mandrel 2545 is alsomovably coupled to the inner surface of the casing 2560 and the outersurface of the lower sealing head 2540. In this manner, the uppersealing head 2535, outer sealing mandrel 2545, and the expansion cone2555 reciprocate in the axial direction. The radial clearance betweenthe outer surface of the outer sealing mandrel 2545 and the innersurface of the casing 2560 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer surface of the outer sealing mandrel 2545 and the innersurface of the casing 2560 ranges from about 0.025 to 0.125 inches inorder to optimally provide stabilization for the expansion cone 2535during the expansion process. The radial clearance between the innersurface of the outer sealing mandrel 2545 and the outer surface of thelower sealing head 2540 may range, for example, from about 0.005 to 0.01inches. In a preferred embodiment, the radial clearance between theinner surface of the outer sealing mandrel 2545 and the outer surface ofthe lower sealing head 2540 ranges from about 0.005 to 0.01 inches inorder to optimally provide minimal radial clearance.

The outer sealing mandrel 2545 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The outersealing mandrel 2545 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the outersealing mandrel 2545 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces.

The outer sealing mandrel 2545 may be coupled to the upper sealing head2535 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the outer sealing mandrel 2545 is removably coupled to the upper sealinghead 2535 by a standard threaded connection. The outer sealing mandrel2545 may be coupled to the expansion cone 2555 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, welding, amorphous bonding, or a standardthreaded connection. In a preferred embodiment, the outer sealingmandrel 2545 is removably coupled to the expansion cone 2555 by astandard threaded connection.

The upper sealing head 2535, the lower sealing head 2540, the innersealing mandrel 2530, and the outer sealing mandrel 2545 together definea pressure chamber 2660. The pressure chamber 2660 is fluidicly coupledto the passage 2590 via one or more passages 2595. During operation ofthe apparatus 2500, the plug 2655 engages with the throat passage 2650to fluidicly isolate the fluid passage 2590 from the fluid passage 2600.The pressure chamber 2660 is then pressurized which in turn causes theupper sealing head 2535, outer sealing mandrel 2545, and expansion cone2555 to reciprocate in the axial direction. The axial motion of theexpansion cone 2555 in turn expands the casing 2560 in the radialdirection.

The load mandrel 2550 is coupled to the lower sealing head 2540. Theload mandrel 2550 preferably comprises an annular member havingsubstantially cylindrical inner and outer surfaces. The load mandrel2550 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the load mandrel2550 is fabricated from stainless steel in order to optimally providehigh strength, corrosion resistance, and low friction surfaces.

The load mandrel 2550 may be coupled to the lower sealing head 2540using any number of conventional commercially available mechanicalcouplings such as, for example, oilfield country tubular goods,drillpipe connection, welding, amorphous bonding, or a standard threadedconnection. In a preferred embodiment, the load mandrel 2550 isremovably coupled to the lower sealing head 2540 by a standard threadedconnection.

The load mandrel 2550 preferably includes a fluid passage 2600 that isadapted to convey fluidic materials from the fluid passage 2590 to theregion outside of the apparatus 2500. In a preferred embodiment, thefluid passage 2600 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud, or lubricants at operatingpressures and flow rates ranging, for example, from about 0 to 9,000 psiand 0 to 3,000 gallons/minute.

The expansion cone 2555 is coupled to the outer sealing mandrel 2545.The expansion cone 2555 is also movably coupled to the inner surface ofthe casing 2560. In this manner, the upper sealing head 2535, outersealing mandrel 2545, and the expansion cone 2555 reciprocate in theaxial direction. The reciprocation of the expansion cone 2555 causes thecasing 2560 to expand in the radial direction.

The expansion cone 2555 preferably comprises an annular member havingsubstantially cylindrical inner and conical outer surfaces. The outsideradius of the outside conical surface may range, for example, from about2 to 34 inches. In a preferred embodiment, the outside radius of theoutside conical surface ranges from about 3 to 28 in order to optimallyprovide radial expansion for the widest variety of tubular casings. Theaxial length of the expansion cone 2555 may range, for example, fromabout 2 to 8 times the largest outside diameter of the expansion cone2535. In a preferred embodiment, the axial length of the expansion cone2535 ranges from about 3 to 5 times the largest outside diameter of theexpansion cone 2535 in order to optimally provide stabilization andcentralization of the expansion cone 2635 during the expansion process.In a particularly preferred embodiment, the maximum outside diameter ofthe expansion cone 2555 is between about 95 to 99% of the insidediameter of the existing wellbore that the casing 2560 will be joinedwith. In a preferred embodiment, the angle of attack of the expansioncone 2555 ranges from about 5 to 30 degrees in order to optimallybalance frictional forces and radial expansion forces. The optimum angleof attack of the expansion cone 2535 will vary as a function of theparticular operational features of the expansion operation.

The expansion cone 2555 may be fabricated from any number ofconventional commercially available materials such as, for example,machine tool steel, nitride steel, titanium, tungsten carbide, ceramicsor other similar high strength materials. In a preferred embodiment, theexpansion cone 2555 is fabricated from D2 machine tool steel in order tooptimally provide high strength, and resistance to wear and galling. Ina particularly preferred embodiment, the outside surface of theexpansion cone 2555 has a surface hardness ranging from about 58 to 62Rockwell C in order to optimally provide high strength and wearresistance.

The expansion cone 2555 may be coupled to the outside sealing mandrel2545 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, welding, amorphous bondingor a standard threaded connection. In a preferred embodiment, theexpansion cone 2555 is coupled to the outside sealing mandrel 2545 usinga standard threaded connection in order to optimally provide highstrength and easy replacement of the expansion cone 2555.

The casing 2560 is removably coupled to the slips 2525 and expansioncone 2555. The casing 2560 preferably comprises a tubular member. Thecasing 2560 may be fabricated from any number of conventionalcommercially available materials such as, for example, slotted tubulars,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the casing 2560 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide high strength using standardized materials.

In a preferred embodiment, the upper end 2665 of the casing 2560includes a thin wall section 2670 and an outer annular sealing member2675. In a preferred embodiment, the wall thickness of the thin wallsection 2670 is about 50 to 100% of the regular wall thickness of thecasing 2560. In this manner, the upper end 2665 of the casing 2560 maybe easily radially expanded and deformed into intimate contact with thelower end of an existing section of wellbore casing. In a preferredembodiment, the lower end of the existing section of casing alsoincludes a thin wall section. In this manner, the radial expansion ofthe thin walled section 2670 of casing 2560 into the thin walled sectionof the existing wellbore casing results in a wellbore casing having asubstantially constant inside diameter.

The annular sealing member 2675 may be fabricated from any number ofconventional commercially available sealing materials such as, forexample, epoxy, rubber, metal, or plastic. In a preferred embodiment,the annular sealing member 2675 is fabricated from StrataLock epoxy inorder to optimally provide compressibility and resistance to wear. Theoutside diameter of the annular sealing member 2675 preferably rangesfrom about 70 to 95% of the inside diameter of the lower section of thewellbore casing that the casing 2560 is joined to. In this manner, afterradial expansion, the annular sealing member 2670 optimally provides afluidic seal and also preferably optimally provides sufficientfrictional force with the inside surface of the existing section ofwellbore casing during the radial expansion of the casing 2560 tosupport the casing 2560.

In a preferred embodiment, the lower end 2680 of the casing 2560includes a thin wall section 2685 and an outer annular sealing member2690. In a preferred embodiment, the wall thickness of the thin wallsection 2685 is about 50 to 100% of the regular wall thickness of thecasing 2560. In this manner, the lower end 2680 of the casing 2560 maybe easily expanded and deformed. Furthermore, in this manner, an othersection of casing may be easily joined with the lower end 2680 of thecasing 2560 using a radial expansion process. In a preferred embodiment,the upper end of the other section of casing also includes a thin wallsection. In this manner, the radial expansion of the thin walled sectionof the upper end of the other casing into the thin walled section 2685of the lower end 2680 of the casing 2560 results in a wellbore casinghaving a substantially constant inside diameter.

The annular sealing member 2690 may be fabricated from any number ofconventional commercially available sealing materials such as, forexample, rubber, metal, plastic or epoxy. In a preferred embodiment, theannular sealing member 2690 is fabricated from StrataLock epoxy in orderto optimally provide compressibility and resistance to wear. The outsidediameter of the annular sealing member 2690 preferably ranges from about70 to 95% of the inside diameter of the lower section of the existingwellbore casing that the casing 2560 is joined to. In this manner, afterradial expansion, the annular sealing member 2690 preferably provides afluidic seal and also preferably provides sufficient frictional forcewith the inside wall of the wellbore during the radial expansion of thecasing 2560 to support the casing 2560.

During operation, the apparatus 2500 is preferably positioned in awellbore with the upper end 2665 of the casing 2560 positioned in anoverlapping relationship with the lower end of an existing wellborecasing. In a particularly preferred embodiment, the thin wall section2670 of the casing 2560 is positioned in opposing overlapping relationwith the thin wall section and outer annular sealing member of the lowerend of the existing section of wellbore casing. In this manner, theradial expansion of the casing 2560 will compress the thin wall sectionsand annular compressible members of the upper end 2665 of the casing2560 and the lower end of the existing wellbore casing into intimatecontact. During the positioning of the apparatus 2500 in the wellbore,the casing 2560 is supported by the expansion cone 2555.

After positioning of the apparatus 2500, a first fluidic material isthen pumped into the fluid passage 2565. The first fluidic material maycomprise any number of conventional commercially available materialssuch as, for example, cement, water, slag-mix, epoxy or drilling mud. Ina preferred embodiment, the first fluidic material comprises ahardenable fluidic sealing material such as, for example, cement, epoxy,or slag-mix in order to optimally provide a hardenable outer annularbody around the expanded casing 2560.

The first fluidic material may be pumped into the fluid passage 2565 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 3,000 gallons/minute. In a preferred embodiment, thefirst fluidic material is pumped into the fluid passage 2565 atoperating pressures and flow rates ranging from about 0 to 3,500 psi and0 to 1,200 gallons/minute in order to optimally provide operationalefficiency.

The first fluidic material pumped into the fluid passage 2565 passesthrough the fluid passages 2570, 2575, 2580, 2590, 2600 and then outsideof the apparatus 2500. The first fluidic material then preferably fillsthe annular region between the outside of the apparatus 2500 and theinterior walls of the wellbore.

The plug 2655 is then introduced into the fluid passage 2565. The plug2655 lodges in the throat passage 2650 and fluidicly isolates and blocksoff the fluid passage 2590. In a preferred embodiment, a couple ofvolumes of a non-hardenable fluidic material are then pumped into thefluid passage 2565 in order to remove any hardenable fluidic materialcontained within and to ensure that none of the fluid passages areblocked.

A second fluidic material is then pumped into the fluid passage 2565.The second fluidic material may comprise any number of conventionalcommercially available materials such as, for example, water, drillinggases, drilling mud or lubricant. In a preferred embodiment, the secondfluidic material comprises a non-hardenable fluidic material such as,for example, water, drilling mud, or lubricant in order to optimallyprovide pressurization of the pressure chamber 2660 and minimizefriction.

The second fluidic material may be pumped into the fluid passage 2565 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thesecond fluidic material is pumped into the fluid passage 2565 atoperating pressures and flow rates ranging from about 0 to 3,500 psi and0 to 1,200 gallons/minute in order to optimally provide operationalefficiency.

The second fluidic material pumped into the fluid passage 2565 passesthrough the fluid passages 2570, 2575, 2580, 2590 and into the pressurechambers 2605 of the slips 2525, and into the pressure chamber 2660.Continued pumping of the second fluidic material pressurizes thepressure chambers 2605 and 2660.

The pressurization of the pressure chambers 2605 causes the slip members2525 to expand in the radial direction and grip the interior surface ofthe casing 2560. The casing 2560 is then preferably maintained in asubstantially stationary position.

The pressurization of the pressure chamber 2660 causes the upper sealinghead 2535, outer sealing mandrel 2545 and expansion cone 2555 to move inan axial direction relative to the casing 2560. In this manner, theexpansion cone 2555 will cause the casing 2560 to expand in the radialdirection, beginning with the lower end 2685 of the casing 2560.

During the radial expansion process, the casing 2560 is prevented frommoving in an upward direction by the slips 2525. A length of the casing2560 is then expanded in the radial direction through the pressurizationof the pressure chamber 2660. The length of the casing 2560 that isexpanded during the expansion process will be proportional to the strokelength of the upper sealing head 2535, outer sealing mandrel 2545, andexpansion cone 2555.

Upon the completion of a stroke, the operating pressure of the secondfluidic material is reduced and the upper sealing head 2535, outersealing mandrel 2545, and expansion cone 2555 drop to their restpositions with the casing 2560 supported by the expansion cone 2555. Theposition of the drillpipe 2505 is preferably adjusted throughout theradial expansion process in order to maintain the overlappingrelationship between the thin walled sections of the lower end of theexisting wellbore casing and the upper end of the casing 2560. In apreferred embodiment, the stroking of the expansion cone 2555 is thenrepeated, as necessary, until the thin walled section 2670 of the upperend 2665 of the casing 2560 is expanded into the thin walled section ofthe lower end of the existing wellbore casing. In this manner, awellbore casing is formed including two adjacent sections of casinghaving a substantially constant inside diameter. This process may thenbe repeated for the entirety of the wellbore to provide a wellborecasing thousands of feet in length having a substantially constantinside diameter.

In a preferred embodiment, during the final stroke of the expansion cone2555, the slips 2525 are positioned as close as possible to the thinwalled section 2670 of the upper end 2665 of the casing 2560 in orderminimize slippage between the casing 2560 and the existing wellborecasing at the end of the radial expansion process. Alternatively, or inaddition, the outside diameter of the annular sealing member 2675 isselected to ensure sufficient interference fit with the inside diameterof the lower end of the existing casing to prevent axial displacement ofthe casing 2560 during the final stroke. Alternatively, or in addition,the outside diameter of the annular sealing member 2690 is selected toprovide an interference fit with the inside walls of the wellbore at anearlier point in the radial expansion process so as to prevent furtheraxial displacement of the casing 2560. In this final alternative, theinterference fit is preferably selected to permit expansion of thecasing 2560 by pulling the expansion cone 2555 out of the wellbore,without having to pressurize the pressure chamber 2660.

During the radial expansion process, the pressurized areas of theapparatus 2500 are preferably limited to the fluid passages 2565, 2570,2575, 2580, and 2590, the pressure chambers 2605 within the slips 2525,and the pressure chamber 2660. No fluid pressure acts directly on thecasing 2560. This permits the use of operating pressures higher than thecasing 2560 could normally withstand.

Once the casing 2560 has been completely expanded off of the expansioncone 2555, the remaining portions of the apparatus 2500 are removed fromthe wellbore. In a preferred embodiment, the contact pressure betweenthe deformed thin wall sections and compressible annular members of thelower end of the existing casing and the upper end 2665 of the casing2560 ranges from about 400 to 10,000 psi in order to optimally supportthe casing 2560 using the existing wellbore casing.

In this manner, the casing 2560 is radially expanded into contact withan existing section of casing by pressurizing the interior fluidpassages 2565, 2570, 2575, 2580, and 2590, the pressure chambers of theslips 2605 and the pressure chamber 2660 of the apparatus 2500.

In a preferred embodiment, as required, the annular body of hardenablefluidic material is then allowed to cure to form a rigid outer annularbody about the expanded casing 2560. In the case where the casing 2560is slotted, the cured fluidic material preferably permeates and envelopsthe expanded casing 2560. The resulting new section of wellbore casingincludes the expanded casing 2560 and the rigid outer annular body. Theoverlapping joint between the pre-existing wellbore casing and theexpanded casing 2560 includes the deformed thin wall sections and thecompressible outer annular bodies. The inner diameter of the resultingcombined wellbore casings is substantially constant. In this manner, amono-diameter wellbore casing is formed. This process of expandingoverlapping tubular members having thin wall end portions withcompressible annular bodies into contact can be repeated for the entirelength of a wellbore. In this manner, a mono-diameter wellbore casingcan be provided for thousands of feet in a subterranean formation.

In a preferred embodiment, as the expansion cone 2555 nears the upperend 2665 of the casing 2560, the operating pressure of the secondfluidic material is reduced in order to minimize shock to the apparatus2500. In an alternative embodiment, the apparatus 2500 includes a shockabsorber for absorbing the shock created by the completion of the radialexpansion of the casing 2560.

In a preferred embodiment, the reduced operating pressure of the secondfluidic material ranges from about 100 to 1,000 psi as the expansioncone 2555 nears the end of the casing 2560 in order to optimally providereduced axial movement and velocity of the expansion cone 2555. In apreferred embodiment, the operating pressure of the second fluidicmaterial is reduced during the return stroke of the apparatus 2500 tothe range of about 0 to 500 psi in order minimize the resistance to themovement of the expansion cone 2555 during the return stroke. In apreferred embodiment, the stroke length of the apparatus 2500 rangesfrom about 10 to 45 feet in order to optimally provide equipmentslengths that can be easily handled using typical oil well riggingequipment and also minimize the frequency at which apparatus 2500 mustbe re-stroked.

In an alternative embodiment, at least a portion of the upper sealinghead 2535 includes an expansion cone for radially expanding the casing2560 during operation of the apparatus 2500 in order to increase thesurface area of the casing 2560 acted upon during the radial expansionprocess. In this manner, the operating pressures can be reduced.

Alternatively, the apparatus 2500 may be used to join a first section ofpipeline to an existing section of pipeline. Alternatively, theapparatus 2500 may be used to directly line the interior of a wellborewith a casing, without the use of an outer annular layer of a hardenablematerial. Alternatively, the apparatus 2500 may be used to expand atubular support member in a hole.

Referring now to FIGS. 19, 19 a and 19 b, another embodiment of anapparatus 2700 for expanding a tubular member will be described. Theapparatus 2700 preferably includes a drillpipe 2705, an innerstringadapter 2710, a sealing sleeve 2715, a first inner sealing mandrel 2720,a first upper sealing head 2725, a first lower sealing head 2730, afirst outer sealing mandrel 2735, a second inner sealing mandrel 2740, asecond upper sealing head 2745, a second lower sealing head 2750, asecond outer sealing mandrel 2755, a load mandrel 2760, an expansioncone 2765, a mandrel launcher 2770, a mechanical slip body 2775,mechanical slips 2780, drag blocks 2785, casing 2790, and fluid passages2795, 2800, 2805, 2810, 2815, 2820, 2825, and 2830.

The drillpipe 2705 is coupled to the innerstring adapter 2710. Duringoperation of the apparatus 2700, the drillpipe 2705 supports theapparatus 2700. The drillpipe 2705 preferably comprises a substantiallyhollow tubular member or members. The drillpipe 2705 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, oilfield country tubular goods, low alloy steel, carbonsteel, stainless steel, or other similar high strength materials. In apreferred embodiment, the drillpipe 2705 is fabricated from coiledtubing in order to facilitate the placement of the apparatus 2700 innon-vertical wellbores. The drillpipe 2705 may be coupled to theinnerstring adapter 2710 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, or a standard threaded connection. In a preferredembodiment, the drillpipe 2705 is removably coupled to the innerstringadapter 2710 by a drillpipe connection in order to optimally providehigh strength and easy disassembly.

The drillpipe 2705 preferably includes a fluid passage 2795 that isadapted to convey fluidic materials from a surface location into thefluid passage 2800. In a preferred embodiment, the fluid passage 2795 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The innerstring adapter 2710 is coupled to the drill string 2705 and thesealing sleeve 2715. The innerstring adapter 2710 preferably comprises asubstantially hollow tubular member or members. The innerstring adapter2710 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the innerstringadapter 2710 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The innerstring adapter 2710 may be coupled to the drill string 2705using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty threaded connection, or a standard threadedconnection. In a preferred embodiment, the innerstring adapter 2710 isremovably coupled to the drill pipe 2705 by a standard threadedconnection in order to optimally provide high strength and easydisassembly. The innerstring adapter 2710 may be coupled to the sealingsleeve 2715 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection,oilfield country tubular goods specialty type threaded connection,ratchet-latch type threaded connection or a standard threadedconnection. In a preferred embodiment, the innerstring adapter 2710 isremovably coupled to the sealing sleeve 2715 by a standard threadedconnection.

The innerstring adapter 2710 preferably includes a fluid passage 2800that is adapted to convey fluidic materials from the fluid passage 2795into the fluid passage 2805. In a preferred embodiment, the fluidpassage 2800 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The sealing sleeve 2716 is coupled to the innerstring adapter 2710 andthe first inner sealing mandrel 2720. The sealing sleeve 2715 preferablycomprises a substantially hollow tubular member or members. The sealingsleeve 2715 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the sealingsleeve 2715 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The sealing sleeve 2715 may be coupled to the innerstring adapter 2710using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the sealing sleeve 2715 is removably coupled to the innerstring adapter2710 by a standard threaded connector. The sealing sleeve 2715 may becoupled to the first inner sealing mandrel 2720 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, welding, amorphous bonding or a standardthreaded connection. In a preferred embodiment, the sealing sleeve 2715is removably coupled to the inner sealing mandrel 2720 by a standardthreaded connection.

The sealing sleeve 2715 preferably includes a fluid passage 2802 that isadapted to convey fluidic materials from the fluid passage 2800 into thefluid passage 2805. In a preferred embodiment, the fluid passage 2802 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The first inner sealing mandrel 2720 is coupled to the sealing sleeve2715 and the first lower sealing head 2730. The first inner sealingmandrel 2720 preferably comprises a substantially hollow tubular memberor members. The first inner sealing mandrel 2720 may be fabricated fromany number of conventional commercially available materials such as, forexample, oilfield country tubular goods, low alloy steel, carbon steel,stainless steel or other similar high strength materials. In a preferredembodiment, the first inner sealing mandrel 2720 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces.

The first inner sealing mandrel 2720 may be coupled to the sealingsleeve 2715 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection oilfieldcountry tubular goods specialty threaded connection, welding, amorphousbonding, or a standard threaded connection. In a preferred embodiment,the first inner sealing mandrel 2720 is removably coupled to the sealingsleeve 2715 by a standard threaded connection. The first inner sealingmandrel 2720 may be coupled to the first lower sealing head 2730 usingany number of conventional commercially available mechanical couplingssuch as, for example, drillpipe connection, oilfield country tubulargoods specialty type threaded connection, welding, amorphous bonding, ora standard threaded connection. In a preferred embodiment, the firstinner sealing mandrel 2720 is removably coupled to the first lowersealing head 2730 by a standard threaded connection.

The first inner sealing mandrel 2720 preferably includes a fluid passage2805 that is adapted to convey fluidic materials from the fluid passage2802 into the fluid passage 2810. In a preferred embodiment, the fluidpassage 2805 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The first upper sealing head 2725 is coupled to the first outer sealingmandrel 2735, the second upper sealing head 2745, the second outersealing mandrel 2755, and the expansion cone 2765. The first uppersealing head 2725 is also movably coupled to the outer surface of thefirst inner sealing mandrel 2720 and the inner surface of the casing2790. In this manner, the first upper sealing head 2725 reciprocates inthe axial direction. The radial clearance between the inner cylindricalsurface of the first upper sealing head 2725 and the outer surface ofthe first inner sealing mandrel 2720 may range, for example, from about0.0025 to 0.05 inches. In a preferred embodiment, the radial clearancebetween the inner cylindrical surface of the first upper sealing head2725 and the outer surface of the first inner sealing mandrel 2720ranges from about 0.005 to 0.125 inches in order to optimally provideminimal radial clearance. The radial clearance between the outercylindrical surface of the first upper sealing head 2725 and the innersurface of the casing 2790 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer cylindrical surface of the first upper sealing head 2725 andthe inner surface of the casing 2790 ranges from about 0.025 to 0.125inches in order to optimally provide stabilization for the expansioncone 2765 during the expansion process.

The first upper sealing head 2725 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The firstupper sealing head 2725 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the first upper sealing head 2725 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance and low friction surfaces. The inner surface of the firstupper sealing head 2725 preferably includes one or more annular sealingmembers 2835 for sealing the interface between the first upper sealinghead 2725 and the first inner sealing mandrel 2720. The sealing members2835 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals ormetal spring energized seals. In a preferred embodiment, the sealingmembers 2835 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for long axial strokes.

In a preferred embodiment, the first upper sealing head 2725 includes ashoulder 2840 for supporting the first upper sealing head 2725 on thefirst lower sealing head 2730.

The first upper sealing head 2725 may be coupled to the first outersealing mandrel 2735 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, welding, amorphous bonding or a standard threadedconnection. In a preferred embodiment, the first upper sealing head 2725is removably coupled to the first outer sealing mandrel 2735 by astandard threaded connection. In a preferred embodiment, the mechanicalcoupling between the first upper sealing head 2725 and the first outersealing mandrel 2735 includes one or more sealing members 2845 forfluidicly sealing the interface between the first upper sealing head2725 and the first outer sealing mandrel 2735. The sealing members 2845may comprise any number of conventional commercially available sealingmembers such as, for example, o-rings, polypak seals or metal springenergized seals. In a preferred embodiment, the sealing members 2845comprise polypak seals available from Parker Seals in order to optimallyprovide sealing for long axial strokes.

The first lower sealing head 2730 is coupled to the first inner sealingmandrel 2720 and the second inner sealing mandrel 2740. The first lowersealing head 2730 is also movably coupled to the inner surface of thefirst outer sealing mandrel 2735. In this manner, the first uppersealing head 2725 and first outer sealing mandrel 2735 reciprocate inthe axial direction. The radial clearance between the outer surface ofthe first lower sealing head 2730 and the inner surface of the firstouter sealing mandrel 2735 may range, for example, from about 0.0025 to0.05 inches. In a preferred embodiment, the radial clearance between theouter surface of the first lower sealing head 2730 and the inner surfaceof the first outer sealing mandrel 2735 ranges from about 0.005 to 0.01inches in order to optimally provide minimal radial clearance.

The first lower sealing head 2730 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The firstlower sealing head 2730 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the first lower sealing head 2730 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces. The outer surface of the firstlower sealing head 2730 preferably includes one or more annular sealingmembers 2850 for sealing the interface between the first lower sealinghead 2730 and the first outer sealing mandrel 2735. The sealing members2850 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals ormetal spring energized seals. In a preferred embodiment, the sealingmembers 2850 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for long axial strokes.

The first lower sealing head 2730 may be coupled to the first innersealing mandrel 2720 using any number of conventional commerciallyavailable mechanical couplings such as, for example, oilfield countrytubular goods specialty threaded connections, welding, amorphousbonding, or standard threaded connection. In a preferred embodiment, thefirst lower sealing head 2730 is removably coupled to the first innersealing mandrel 2720 by a standard threaded connection. In a preferredembodiment, the mechanical coupling between the first lower sealing head2730 and the first inner sealing mandrel 2720 includes one or moresealing members 2855 for fluidicly sealing the interface between thefirst lower sealing head 2730 and the first inner sealing mandrel 2720.The sealing members 2855 may comprise any number of conventionalcommercially available sealing members such as, for example, o-rings,polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 2855 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for long axialstrokes.

The first lower sealing head 2730 may be coupled to the second innersealing mandrel 2740 using any number of conventional commerciallyavailable mechanical couplings such as, for example, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, the lowersealing head 2730 is removably coupled to the second inner sealingmandrel 2740 by a standard threaded connection. In a preferredembodiment, the mechanical coupling between the first lower sealing head2730 and the second inner sealing mandrel 2740 includes one or moresealing members 2860 for fluidicly sealing the interface between thefirst lower sealing head 2730 and the second inner sealing mandrel 2740.The sealing members 2860 may comprise any number of conventionalcommercially available sealing members such as, for example, o-rings,polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 2860 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for long axialstrokes.

The first outer sealing mandrel 2735 is coupled to the first uppersealing head 2725, the second upper sealing head 2745, the second outersealing mandrel 2755, and the expansion cone 2765. The first outersealing mandrel 2735 is also movably coupled to the inner surface of thecasing 2790 and the outer surface of the first lower sealing head 2730.In this manner, the first upper sealing head 2725, first outer sealingmandrel 2735, second upper sealing head 2745, second outer sealingmandrel 2755, and the expansion cone 2765 reciprocate in the axialdirection. The radial clearance between the outer surface of the firstouter sealing mandrel 2735 and the inner surface of the casing 2790 mayrange, for example, from about 0.025 to 0.375 inches. In a preferredembodiment, the radial clearance between the outer surface of the firstouter sealing mandrel 2735 and the inner surface of the casing 2790ranges from about 0.025 to 0.125 inches in order to optimally providestabilization for the expansion cone 2765 during the expansion process.The radial clearance between the inner surface of the first outersealing mandrel 2735 and the outer surface of the first lower sealinghead 2730 may range, for example, from about 0.0025 to 0.05 inches. In apreferred embodiment, the radial clearance between the inner surface ofthe first outer sealing mandrel 2735 and the outer surface of the firstlower sealing head 2730 ranges from about 0.005 to 0.01 inches in orderto optimally provide minimal radial clearance.

The outer sealing mandrel 1935 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The firstouter sealing mandrel 2735 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the first outer sealing mandrel 2735 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces.

The first outer sealing mandrel 2735 may be coupled to the first uppersealing head 2725 using any number of conventional commerciallyavailable mechanical couplings such as, for example, oilfield countrytubular goods, welding, amorphous bonding, or a standard threadedconnection. In a preferred embodiment, the first outer sealing mandrel2735 is removably coupled to the first upper sealing head 2725 by astandard threaded connection. The first outer sealing mandrel 2735 maybe coupled to the second upper sealing head 2745 using any number ofconventional commercially available mechanical couplings such as, forexample, oilfield country tubular goods specialty threaded connection,welding, amorphous bonding, or a standard threaded connection. In apreferred embodiment, the first outer sealing mandrel 2735 is removablycoupled to the second upper sealing head 2745 by a standard threadedconnection.

The second inner sealing mandrel 2740 is coupled to the first lowersealing head 2730 and the second lower sealing head 2750. The secondinner sealing mandrel 2740 preferably comprises a substantially hollowtubular member or members. The second inner sealing mandrel 2740 may befabricated from any number of conventional commercially availablematerials such as, for example, oilfield country tubular goods, lowalloy steel, carbon steel, stainless steel or other similar highstrength materials. In a preferred embodiment, the second inner sealingmandrel 2740 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The second inner sealing mandrel 2740 may be coupled to the first lowersealing head 2730 using any number of conventional commerciallyavailable mechanical couplings such as, for example, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, the secondinner sealing mandrel 2740 is removably coupled to the first lowersealing head 2740 by a standard threaded connection. The mechanicalcoupling between the second inner sealing mandrel 2740 and the firstlower sealing head 2730 preferably includes sealing members 2860.

The second inner sealing mandrel 2740 may be coupled to the second lowersealing head 2750 using any number of conventional commerciallyavailable mechanical couplings such as, for example, oilfield countrytubular goods specialty threaded connection, welding, amorphous bonding,or a standard threaded connection. In a preferred embodiment, the secondinner sealing mandrel 2720 is removably coupled to the second lowersealing head 2750 by a standard threaded connection. In a preferredembodiment, the mechanical coupling between the second inner sealingmandrel 2740 and the second lower sealing head 2750 includes one or moresealing members 2865. The sealing members 2865 may comprise any numberof conventional commercially available seals such as, for example,o-rings, polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 2865 comprise polypak seals availablefrom Parker Seals.

The second inner sealing mandrel 2740 preferably includes a fluidpassage 2810 that is adapted to convey fluidic materials from the fluidpassage 2805 into the fluid passage 2815. In a preferred embodiment, thefluid passage 2810 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The second upper sealing head 2745 is coupled to the first upper sealinghead 2725, the first outer sealing mandrel 2735, the second outersealing mandrel 2755, and the expansion cone 2765. The second uppersealing head 2745 is also movably coupled to the outer surface of thesecond inner sealing mandrel 2740 and the inner surface of the casing2790. In this manner, the second upper sealing head 2745 reciprocates inthe axial direction. The radial clearance between the inner cylindricalsurface of the second upper sealing head 2745 and the outer surface ofthe second inner sealing mandrel 2740 may range, for example, from about0.0025 to 0.05 inches. In a preferred embodiment, the radial clearancebetween the inner cylindrical surface of the second upper sealing head2745 and the outer surface of the second inner sealing mandrel 2740ranges from about 0.005 to 0.01 inches in order to optimally provideminimal radial clearance. The radial clearance between the outercylindrical surface of the second upper sealing head 2745 and the innersurface of the casing 2790 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer cylindrical surface of the second upper sealing head 2745 andthe inner surface of the casing 2790 ranges from about 0.025 to 0.125inches in order to optimally provide stabilization for the expansioncone 2765 during the expansion process.

The second upper sealing head 2745 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thesecond upper sealing head 2745 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the second upper sealing head 2745 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces. The inner surface of the secondupper sealing head 2745 preferably includes one or more annular sealingmembers 2870 for sealing the interface between the second upper sealinghead 2745 and the second inner sealing mandrel 2740. The sealing members2870 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals, ormetal spring energized seals. In a preferred embodiment, the sealingmembers 2870 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for long axial strokes.

In a preferred embodiment, the second upper sealing head 2745 includes ashoulder 2875 for supporting the second upper sealing head 2745 on thesecond lower sealing head 2750.

The second upper sealing head 2745 may be coupled to the first outersealing mandrel 2735 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, ratchet-latch type threaded connection, or a standardthreaded connection. In a preferred embodiment, the second upper sealinghead 2745 is removably coupled to the first outer sealing mandrel 2735by a standard threaded connection. In a preferred embodiment, themechanical coupling between the second upper sealing head 2745 and thefirst outer sealing mandrel 2735 includes one or more sealing members2880 for fluidicly sealing the interface between the second uppersealing head 2745 and the first outer sealing mandrel 2735. The sealingmembers 2880 may comprise any number of conventional commerciallyavailable sealing members such as, for example, o-rings, polypak sealsor metal spring energized seals. In a preferred embodiment, the sealingmembers 2880 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for a long axial stroke.

The second upper sealing head 2745 may be coupled to the second outersealing mandrel 2755 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, or a standard threaded connection. In a preferredembodiment, the second upper sealing head 2745 is removably coupled tothe second outer sealing mandrel 2755 by a standard threaded connection.In a preferred embodiment, the mechanical coupling between the secondupper sealing head 2745 and the second outer sealing mandrel 2755includes one or more sealing members 2885 for fluidicly sealing theinterface between the second upper sealing head 2745 and the secondouter sealing mandrel 2755. The sealing members 2885 may comprise anynumber of conventional commercially available sealing members such as,for example, o-rings, polypak seals or metal spring energized seals. Ina preferred embodiment, the sealing members 2885 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing forlong axial strokes.

The second lower sealing head 2750 is coupled to the second innersealing mandrel 2740 and the load mandrel 2760. The second lower sealinghead 2750 is also movably coupled to the inner surface of the secondouter sealing mandrel 2755. In this manner, the first upper sealing head2725, the first outer sealing mandrel 2735, second upper sealing head2745, second outer sealing mandrel 2755, and the expansion cone 2765reciprocate in the axial direction. The radial clearance between theouter surface of the second lower sealing head 2750 and the innersurface of the second outer sealing mandrel 2755 may range, for example,from about 0.0025 to 0.05 inches. In a preferred embodiment, the radialclearance between the outer surface of the second lower sealing head2750 and the inner surface of the second outer sealing mandrel 2755ranges from about 0.005 to 0.01 inches in order to optimally provideminimal radial clearance.

The second lower sealing head 2750 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thesecond lower sealing head 2750 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the second lower sealing head 2750 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces. The outer surface of the secondlower sealing head 2750 preferably includes one or more annular sealingmembers 2890 for sealing the interface between the second lower sealinghead 2750 and the second outer sealing mandrel 2755. The sealing members2890 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals ormetal spring energized seals. In a preferred embodiment, the sealingmembers 2890 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for long axial strokes.

The second lower sealing head 2750 may be coupled to the second innersealing mandrel 2740 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, ratchet-latch type threaded connection, or a standardthreaded connection. In a preferred embodiment, the second lower sealinghead 2750 is removably coupled to the second inner sealing mandrel 2740by a standard threaded connection. In a preferred embodiment, themechanical coupling between the second lower sealing head 2750 and thesecond inner sealing mandrel 2740 includes one or more sealing members2895 for fluidicly sealing the interface between the second sealing head2750 and the second sealing mandrel 2740. The sealing members 2895 maycomprise any number of conventional commercially available sealingmembers such as, for example, o-rings, polypak seals or metal springenergized seals. In a preferred embodiment, the sealing members 2895comprise polypak seals available from Parker Seals in order to optimallyprovide sealing for a long axial stroke.

The second lower sealing head 2750 may be coupled to the load mandrel2760 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield tubulargoods specialty threaded connection, ratchet-latch type threadedconnection, or a standard threaded connection. In a preferredembodiment, the second lower sealing head 2750 is removably coupled tothe load mandrel 2760 by a standard threaded connection. In a preferredembodiment, the mechanical coupling between the second lower sealinghead 2750 and the load mandrel 2760 includes one or more sealing members2900 for fluidicly sealing the interface between the second lowersealing head 2750 and the load mandrel 2760. The sealing members 2900may comprise any number of conventional commercially available sealingmembers such as, for example, o-rings, polypak seals or metal springenergized seals. In a preferred embodiment, the sealing members 2900comprise polypak seals available from Parker Seals in order to optimallyprovide sealing for long axial strokes.

In a preferred embodiment, the second lower sealing head 2750 includes athroat passage 2905 fluidicly coupled between the fluid passages 2810and 2815. The throat passage 2905 is preferably of reduced size and isadapted to receive and engage with a plug 2910, or other similar device.In this manner, the fluid passage 2810 is fluidicly isolated from thefluid passage 2815. In this manner, the pressure chambers 2915 and 2920are pressurized. The use of a plurality of pressure chambers in theapparatus 2700 permits the effective driving force to be multiplied.While illustrated using a pair of pressure chambers, 2915 and 2920, theapparatus 2700 may be further modified to employ additional pressurechambers.

The second outer sealing mandrel 2755 is coupled to the first uppersealing head 2725, the first outer sealing mandrel 2735, the secondupper sealing head 2745, and the expansion cone 2765. The second outersealing mandrel 2755 is also movably coupled to the inner surface of thecasing 2790 and the outer surface of the second lower sealing head 2750.In this manner, the first upper sealing head 2725, first outer sealingmandrel 2735, second upper sealing head 2745, second outer sealingmandrel 2755, and the expansion cone 2765 reciprocate in the axialdirection.

The radial clearance between the outer surface of the second outersealing mandrel 2755 and the inner surface of the casing 2790 may range,for example, from about 0.025 to 0.375 inches. In a preferredembodiment, the radial clearance between the outer surface of the secondouter sealing mandrel 2755 and the inner surface of the casing 2790ranges from about 0.025 to 0.125 inches in order to optimally providestabilization for the expansion cone 2765 during the expansion process.The radial clearance between the inner surface of the second outersealing mandrel 2755 and the outer surface of the second lower sealinghead 2750 may range, for example, from about 0.0025 to 0.05 inches. In apreferred embodiment, the radial clearance between the inner surface ofthe second outer sealing mandrel 2755 and the outer surface of thesecond lower sealing head 2750 ranges from about 0.005 to 0.01 inches inorder to optimally provide minimal radial clearance.

The second outer sealing mandrel 2755 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thesecond outer sealing mandrel 2755 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the second outer sealing mandrel 2755 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces.

The second outer sealing mandrel 2755 may be coupled to the second uppersealing head 2745 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, ratchet-latch type threaded connection or a standardthreaded connection. In a preferred embodiment, the second outer sealingmandrel 2755 is removably coupled to the second upper sealing head 2745by a standard threaded connection. The second outer sealing mandrel 2755may be coupled to the expansion cone 2765 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, ratchet-latch type threaded connection, or astandard threaded connection. In a preferred embodiment, the secondouter sealing mandrel 2755 is removably coupled to the expansion cone2765 by a standard threaded connection.

The load mandrel 2760 is coupled to the second lower sealing head 2750and the mechanical slip body 2755. The load mandrel 2760 preferablycomprises an annular member having substantially cylindrical inner andouter surfaces. The load mandrel 2760 may be fabricated from any numberof conventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the load mandrel 2760 is fabricated from stainless steel inorder to optimally provide high strength, corrosion resistance, and lowfriction surfaces.

The load mandrel 2760 may be coupled to the second lower sealing head2750 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, ratchet-latch typethreaded connection, or a standard threaded connection. In a preferredembodiment, the load mandrel 2760 is removably coupled to the secondlower sealing head 2750 by a standard threaded connection. The loadmandrel 2760 may be coupled to the mechanical slip body 2775 using anynumber of conventional commercially available mechanical couplings suchas, for example, drillpipe connection, oilfield country tubular goodsspecialty type threaded connection, ratchet-latch type threadedconnection or a standard threaded connection. In a preferred embodiment,the load mandrel 2760 is removably coupled to the mechanical slip body2775 by a standard threaded connection.

The load mandrel 2760 preferably includes a fluid passage 2815 that isadapted to convey fluidic materials from the fluid passage 2810 to thefluid passage 2820. In a preferred embodiment, the fluid passage 2815 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The expansion cone 2765 is coupled to the second outer sealing mandrel2755. The expansion cone 2765 is also movably coupled to the innersurface of the casing 2790. In this manner, the first upper sealing head2725, first outer sealing mandrel 2735, second upper sealing head 2745,second outer sealing mandrel 2755, and the expansion cone 2765reciprocate in the axial direction. The reciprocation of the expansioncone 2765 causes the casing 2790 to expand in the radial direction.

The expansion cone 2765 preferably comprises an annular member havingsubstantially cylindrical inner and conical outer surfaces. The outsideradius of the outside conical surface may range, for example, from about2 to 34 inches. In a preferred embodiment, the outside radius of theoutside conical surface ranges from about 3 to 28 inches in order tooptimally provide expansion cone dimensions that accommodate the typicalrange of casings. The axial length of the expansion cone 2765 may range,for example, from about 2 to 8 times the largest outer diameter of theexpansion cone 2765. In a preferred embodiment, the axial length of theexpansion cone 2765 ranges from about 3 to 5 times the largest outerdiameter of the expansion cone 2765 in order to optimally providestabilization and centralization of the expansion cone 2765. In apreferred embodiment, the angle of attack of the expansion cone 2765ranges from about 5 to 30 degrees in order to optimally balancefrictional forces and radial expansion forces.

The expansion cone 2765 may be fabricated from any number ofconventional commercially available materials such as, for example,machine tool steel, nitride steel, titanium, tungsten carbide, ceramicsor other similar high strength materials. In a preferred embodiment, theexpansion cone 2765 is fabricated from D2 machine tool steel in order tooptimally provide high strength and resistance to corrosion and galling.In a particularly preferred embodiment, the outside surface of theexpansion cone 2765 has a surface hardness ranging from about 58 to 62Rockwell C in order to optimally provide high strength and resistance towear and galling.

The expansion cone 2765 may be coupled to the second outside sealingmandrel 2765 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection,oilfield country tubular goods specialty type threaded connection,ratchet-latch type threaded connection or a standard threadedconnection. In a preferred embodiment, the expansion cone 2765 iscoupled to the second outside sealing mandrel 2765 using a standardthreaded connection in order to optimally provide high strength and easyreplacement of the expansion cone 2765.

The mandrel launcher 2770 is coupled to the casing 2790. The mandrellauncher 2770 comprises a tubular section of casing having a reducedwall thickness compared to the casing 2790. In a preferred embodiment,the wall thickness of the mandrel launcher 2770 is about 50 to 100% ofthe wall thickness of the casing 2790. The wall thickness of the mandrellauncher 2770 may range, for example, from about 0.15 to 1.5 inches. Ina preferred embodiment, the wall thickness of the mandrel launcher 2770ranges from about 0.25 to 0.75 inches. In this manner, the initiation ofthe radial expansion of the casing 2790 is facilitated, the placement ofthe apparatus 2700 within a wellbore casing and wellbore is facilitated,and the mandrel launcher 2770 has a burst strength approximately equalto that of the casing 2790.

The mandrel launcher 2770 may be coupled to the casing 2790 using anynumber of conventional mechanical couplings such as, for example, astandard threaded connection. The mandrel launcher 2770 may befabricated from any number of conventional commercially availablematerials such as, for example, oilfield country tubular goods, lowalloy steel, carbon steel, stainless steel, or other similar highstrength materials. In a preferred embodiment, the mandrel launcher 2770is fabricated from oilfield country tubular goods of higher strengththan that of the casing 2790 but with a reduced wall thickness in orderto optimally provide a small compact tubular container having a burststrength approximately equal to that of the casing 2790.

The mechanical slip body 2775 is coupled to the load mandrel 2760, themechanical slips 2780, and the drag blocks 2785. The mechanical slipbody 2775 preferably comprises a tubular member having an inner passage2820 fluidicly coupled to the passage 2815. In this manner, fluidicmaterials may be conveyed from the passage 2820 to a region outside ofthe apparatus 2700.

The mechanical slip body 2775 may be coupled to the load mandrel 2760using any number of conventional mechanical couplings. In a preferredembodiment, the mechanical slip body 2775 is removably coupled to theload mandrel 2760 using a standard threaded connection in order tooptimally provide high strength and easy disassembly. The mechanicalslip body 2775 may be coupled to the mechanical slips 2780 using anynumber of conventional mechanical couplings. In a preferred embodiment,the mechanical slip body 2755 is removably coupled to the mechanicalslips 2780 using threaded connections and sliding steel retainer ringsin order to optimally provide a high strength attachment. The mechanicalslip body 2755 may be coupled to the drag blocks 2785 using any numberof conventional mechanical couplings. In a preferred embodiment, themechanical slip body 2775 is removably coupled to the drag blocks 2785using threaded connections and sliding steel retainer rings in order tooptimally provide a high strength attachment.

The mechanical slip body 2775 preferably includes a fluid passage 2820that is adapted to convey fluidic materials from the fluid passage 2815to the region outside of the apparatus 2700. In a preferred embodiment,the fluid passage 2820 is adapted to convey fluidic materials such as,for example, cement, epoxy, water, drilling mud or lubricants atoperating pressures and flow rates ranging from about 0 to 9,000 psi and0 to 3,000 gallons/minute.

The mechanical slips 2780 are coupled to the outside surface of themechanical slip body 2775. During operation of the apparatus 2700, themechanical slips 2780 prevent upward movement of the casing 2790 andmandrel launcher 2770. In this manner, during the axial reciprocation ofthe expansion cone 2765, the casing 2790 and mandrel launcher 2770 aremaintained in a substantially stationary position. In this manner, themandrel launcher 2765 and casing 2790 and mandrel launcher 2770 areexpanded in the radial direction by the axial movement of the expansioncone 2765.

The mechanical slips 2780 may comprise any number of conventionalcommercially available mechanical slips such as, for example, RTTSpacker tungsten carbide mechanical slips, RTTS packer wicker typemechanical slips or Model 3L retrievable bridge plug tungsten carbideupper mechanical slips. In a preferred embodiment, the mechanical slips2780 comprise RTTS packer tungsten carbide mechanical slips availablefrom Halliburton Energy Services in order to optimally provideresistance to axial movement of the casing 2790 and mandrel launcher2770 during the expansion process.

The drag blocks 2785 are coupled to the outside surface of themechanical slip body 2775. During operation of the apparatus 2700, thedrag blocks 2785 prevent upward movement of the casing 2790 and mandrellauncher 2770. In this manner, during the axial reciprocation of theexpansion cone 2765, the casing 2790 and mandrel launcher 2770 aremaintained in a substantially stationary position. In this manner, themandrel launcher 2770 and casing 2790 are expanded in the radialdirection by the axial movement of the expansion cone 2765.

The drag blocks 2785 may comprise any number of conventionalcommercially available mechanical slips such as, for example, RTTSpacker mechanical drag blocks or Model 3L retrievable bridge plug dragblocks. In a preferred embodiment, the drag blocks 2785 comprise RTTSpacker mechanical drag blocks available from Halliburton Energy Servicesin order to optimally provide resistance to axial movement of the casing2790 and mandrel launcher 2770 during the expansion process.

The casing 2790 is coupled to the mandrel launcher 2770. The casing 2790is further removably coupled to the mechanical slips 2780 and dragblocks 2785. The casing 2790 preferably comprises a tubular member. Thecasing 2790 may be fabricated from any number of conventionalcommercially available materials such as, for example, slotted tubulars,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the casing 2790 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide high strength using standardized materials. In apreferred embodiment, the upper end of the casing 2790 includes one ormore sealing members positioned about the exterior of the casing 2790.

During operation, the apparatus 2700 is positioned in a wellbore withthe upper end of the casing 2790 positioned in an overlappingrelationship within an existing wellbore casing. In order minimize surgepressures within the borehole during placement of the apparatus 2700,the fluid passage 2795 is preferably provided with one or more pressurerelief passages. During the placement of the apparatus 2700 in thewellbore, the casing 2790 is supported by the expansion cone 2765.

After positioning of the apparatus 2700 within the bore hole in anoverlapping relationship with an existing section of wellbore casing, afirst fluidic material is pumped into the fluid passage 2795 from asurface location. The first fluidic material is conveyed from the fluidpassage 2795 to the fluid passages 2800, 2802, 2805, 2810, 2815, and2820. The first fluidic material will then exit the apparatus 2700 andfill the annular region between the outside of the apparatus 2700 andthe interior walls of the bore hole.

The first fluidic material may comprise any number of conventionalcommercially available materials such as, for example, epoxy, drillingmud, slag mix, water or cement. In a preferred embodiment, the firstfluidic material comprises a hardenable fluidic sealing material suchas, for example, slag mix, epoxy, or cement. In this manner, a wellborecasing having an outer annular layer of a hardenable material may beformed.

The first fluidic material may be pumped into the apparatus 2700 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 3,000 gallons/minute. In a preferred embodiment, thefirst fluidic material is pumped into the apparatus 2700 at operatingpressures and flow rates ranging from about 0 to 3,500 psi and 0 to1,200 gallons/minute in order to optimally provide operationalefficiency.

At a predetermined point in the injection of the first fluidic materialsuch as, for example, after the annular region outside of the apparatus2700 has been filled to a predetermined level, a plug 2910, dart, orother similar device is introduced into the first fluidic material. Theplug 2910 lodges in the throat passage 2905 thereby fluidicly isolatingthe fluid passage 2810 from the fluid passage 2815.

After placement of the plug 2910 in the throat passage 2905, a secondfluidic material is pumped into the fluid passage 2795 in order topressurize the pressure chambers 2915 and 2920. The second fluidicmaterial may comprise any number of conventional commercially availablematerials such as, for example, water, drilling gases, drilling mud orlubricants. In a preferred embodiment, the second fluidic materialcomprises a non-hardenable fluidic material such as, for example, water,drilling mud or lubricant. The use of lubricant optimally provideslubrication of the moving parts of the apparatus 2700.

The second fluidic material may be pumped into the apparatus 2700 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thesecond fluidic material is pumped into the apparatus 2700 at operatingpressures and flow rates ranging from about 0 to 3,500 psi and 0 to1,200 gallons/minute in order to optimally provide operationalefficiency.

The pressurization of the pressure chambers 2915 and 2920 cause theupper sealing heads, 2725 and 2745, outer sealing mandrels, 2735 and2755, and expansion cone 2765 to move in an axial direction. As theexpansion cone 2765 moves in the axial direction, the expansion cone2765 pulls the mandrel launcher 2770, casing 2790, and drag blocks 2785along, which sets the mechanical slips 2780 and stops further axialmovement of the mandrel launcher 2770 and casing 2790. In this manner,the axial movement of the expansion cone 2765 radially expands themandrel launcher 2770 and casing 2790.

Once the upper sealing heads, 2725 and 2745, outer sealing mandrels,2735 and 2755, and expansion cone 2765 complete an axial stroke, theoperating pressure of the second fluidic material is reduced and thedrill string 2705 is raised. This causes the inner sealing mandrels,2720 and 2740, lower sealing heads, 2730 and 2750, load mandrel 2760,and mechanical slip body 2755 to move upward. This unsets the mechanicalslips 2780 and permits the mechanical slips 2780 and drag 2785 to bemoved upward within the mandrel launcher 2770 and casing 2790. When thelower sealing heads, 2730 and 2750, contact the upper sealing heads,2725 and 2745, the second fluidic material is again pressurized and theradial expansion process continues. In this manner, the mandrel launcher2770 and casing 2790 are radially expanded through repeated axialstrokes of the upper sealing heads, 2725 and 2745, outer sealingmandrels, 2735 and 2755, and expansion cone 2765. Throughout the radialexpansion process, the upper end of the casing 2790 is preferablymaintained in an overlapping relation with an existing section ofwellbore casing.

At the end of the radial expansion process, the upper end of the casing2790 is expanded into intimate contact with the inside surface of thelower end of the existing wellbore casing. In a preferred embodiment,the sealing members provided at the upper end of the casing 2790 providea fluidic seal between the outside surface of the upper end of thecasing 2790 and the inside surface of the lower end of the existingwellbore casing. In a preferred embodiment, the contact pressure betweenthe casing 2790 and the existing section of wellbore casing ranges fromabout 400 to 10,000 in order to optimally provide contact pressure foractivating the sealing members, provide optimal resistance to axialmovement of the expanded casing, and optimally resist typical tensileand compressive loads on the expanded casing.

In a preferred embodiment, as the expansion cone 2765 nears the end ofthe casing 2790, the operating pressure of the second fluidic materialis reduced in order to minimize shock to the apparatus 2700. In analternative embodiment, the apparatus 2700 includes a shock absorber forabsorbing the shock created by the completion of the radial expansion ofthe casing 2790.

In a preferred embodiment, the reduced operating pressure of the secondfluidic material ranges from about 100 to 1,000 psi as the expansioncone 2765 nears the end of the casing 2790 in order to optimally providereduced axial movement and velocity of the expansion cone 2765. In apreferred embodiment, the operating pressure of the second fluidicmaterial is reduced during the return stroke of the apparatus 2700 tothe range of about 0 to 500 psi in order minimize the resistance to themovement of the expansion cone 2765 during the return stroke. In apreferred embodiment, the stroke length of the apparatus 2700 rangesfrom about 10 to 45 feet in order to optimally provide equipment thatcan be easily handled by typical oil well rigging equipment and minimizethe frequency at which the apparatus 2700 must be re-stroked during anexpansion operation.

In an alternative embodiment, at least a portion of the upper sealingheads, 2725 and 2745, include expansion cones for radially expanding themandrel launcher 2770 and casing 2790 during operation of the apparatus2700 in order to increase the surface area of the casing 2790 acted uponduring the radial expansion process. In this manner, the operatingpressures can be reduced.

In an alternative embodiment, mechanical slips are positioned in anaxial location between the sealing sleeve 1915 and the first innersealing mandrel 2720 in order to optimally provide a simplified assemblyand operation of the apparatus 2700.

Upon the complete radial expansion of the casing 2790, if applicable,the first fluidic material is permitted to cure within the annularregion between the outside of the expanded casing 2790 and the interiorwalls of the wellbore. In the case where the casing 2790 is slotted, thecured fluidic material preferably permeates and envelops the expandedcasing 2790. In this manner, a new-section of wellbore casing is formedwithin a wellbore. Alternatively, the apparatus 2700 may be used to joina first section of pipeline to an existing section of pipeline.Alternatively, the apparatus 2700 may be used to directly line theinterior of a wellbore with a casing, without the use of an outerannular layer of a hardenable material. Alternatively, the apparatus2700 may be used to expand a tubular support member in a hole.

During the radial expansion process, the pressurized areas of theapparatus 2700 are limited to the fluid passages 2795, 2800, 2802, 2805,and 2810, and the pressure chambers 2915 and 2920. No fluid pressureacts directly on the mandrel launcher 2770 and casing 2790. This permitsthe use of operating pressures higher than the mandrel launcher 2770 andcasing 2790 could normally withstand.

Referring now to FIG. 20, a preferred embodiment of an apparatus 3000for forming a mono-diameter wellbore casing will be described. Theapparatus 3000 preferably includes a drillpipe 3005, an innerstringadapter 3010, a sealing sleeve 3015, a first inner sealing mandrel 3020,hydraulic slips 3025, a first upper sealing head 3030, a first lowersealing head 3035, a first outer sealing mandrel 3040, a second innersealing mandrel 3045, a second upper sealing head 3050, a second lowersealing head 3055, a second outer sealing mandrel 3060, load mandrel3065, expansion cone 3070, casing 3075, and fluid passages 3080, 3085,3090, 3095, 3100, 3105, 3110, 3115 and 3120.

The drillpipe 3005 is coupled to the innerstring adapter 3010. Duringoperation of the apparatus 3000, the drillpipe 3005 supports theapparatus 3000. The drillpipe 3005 preferably comprises a substantiallyhollow tubular member or members. The drillpipe 3005 may be fabricatedfrom any number of conventional commercially available materials suchas, for example, oilfield country tubular goods, low alloy steel, carbonsteel, stainless steel or other similar high strength materials. In apreferred embodiment, the drillpipe 3005 is fabricated from coiledtubing in order to faciliate the placement of the apparatus 3000 innon-vertical wellbores. The drillpipe 3005 may be coupled to theinnerstring adapter 3010 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty threadedconnection, or a standard threaded connection. In a preferredembodiment, the drillpipe 3005 is removably coupled to the innerstringadapter 3010 by a drillpipe connection.

The drillpipe 3005 preferably includes a fluid passage 3080 that isadapted to convey fluidic materials from a surface location into thefluid passage 3085. In a preferred embodiment, the fluid passage 3080 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The innerstring adapter 3010 is coupled to the drill string 3005 and thesealing sleeve 3015. The innerstring adapter 3010 preferably comprises asubstantially hollow tubular member or members. The innerstring adapter3010 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel, or other similarhigh strength materials. In a preferred embodiment, the innerstringadapter 3010 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The innerstring adapter 3010 may be coupled to the drill string 3005using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnection. In a preferred embodiment, the innerstring adapter 3010 isremovably coupled to the drill pipe 3005 by a drillpipe connection. Theinnerstring adapter 3010 may be coupled to the sealing sleeve 3015 usingany number of conventional commercially available mechanical couplingssuch as, for example, drillpipe connection, oilfield country tubulargoods specialty type threaded connection, ratchet-latch type threadedconnection or a standard threaded connection. In a preferred embodiment,the innerstring adapter 3010 is removably coupled to the sealing sleeve3015 by a standard threaded connection.

The innerstring adapter 3010 preferably includes a fluid passage 3085that is adapted to convey fluidic materials from the fluid passage 3080into the fluid passage 3090. In a preferred embodiment, the fluidpassage 3085 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The sealing sleeve 3015 is coupled to the innerstring adapter 3010 andthe first inner sealing mandrel 3020. The sealing sleeve 3015 preferablycomprises a substantially hollow tubular member or members. The sealingsleeve 3015 may be fabricated from any number of conventionalcommercially available materials such as, for example, oilfield countrytubular goods, low alloy steel, carbon steel, stainless steel or othersimilar high strength materials. In a preferred embodiment, the sealingsleeve 3015 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The sealing sleeve 3015 may be coupled to the innerstring adapter 3010using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, ratchet-latch typeconnection or a standard threaded connection. In a preferred embodiment,the sealing sleeve 3015 is removably coupled to the innerstring adapter3010 by a standard threaded connection. The sealing sleeve 3015 may becoupled to the first inner sealing mandrel 3020 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, ratchet-latch type threaded connection or astandard threaded connection. In a preferred embodiment, the sealingsleeve 3015 is removably coupled to the first inner sealing mandrel 3020by a standard threaded connection.

The sealing sleeve 3015 preferably includes a fluid passage 3090 that isadapted to convey fluidic materials from the fluid passage 3085 into thefluid passage 3095. In a preferred embodiment, the fluid passage 3090 isadapted to convey fluidic materials such as, for example, cement, epoxy,water, drilling mud, or lubricants at operating pressures and flow ratesranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.

The first inner sealing mandrel 3020 is coupled to the sealing sleeve3015, the hydraulic slips 3025, and the first lower sealing head 3035.The first inner sealing mandrel 3020 is further movably coupled to thefirst upper sealing head 3030. The first inner sealing mandrel 3020preferably comprises a substantially hollow tubular member or members.The first inner sealing mandrel 3020 may be fabricated from any numberof conventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel, or similar high strength materials. In a preferred embodiment,the first inner sealing mandrel 3020 is fabricated from stainless steelin order to optimally provide high strength, corrosion resistance, andlow friction surfaces.

The first inner sealing mandrel 3020 may be coupled to the sealingsleeve 3015 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection,oilfield country tubular goods specialty type threaded connection,ratchet-latch type threaded connection or a standard threadedconnection. In a preferred embodiment, the first inner sealing mandrel3020 is removably coupled to the sealing sleeve 3015 by a standardthreaded connection. The first inner sealing mandrel 3020 may be coupledto the hydraulic slips 3025 using any number of conventionalcommercially available mechanical couplings such as, for example,drillpipe connection, oilfield country tubular goods specialty typethreaded connection, ratchet-latch type threaded connection or astandard threaded connection. In a preferred embodiment, the first innersealing mandrel 3020 is removably coupled to the hydraulic slips 3025 bya standard threaded connection. The first inner sealing mandrel 3020 maybe coupled to the first lower sealing head 3035 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, ratchet-latch type threaded connection or astandard threaded connection. In a preferred embodiment, the first innersealing mandrel 3020 is removably coupled to the first lower sealinghead 3035 by a standard threaded connection.

The first inner sealing mandrel 3020 preferably includes a fluid passage3095 that is adapted to convey fluidic materials from the fluid passage3090 into the fluid passage 3100. In a preferred embodiment, the fluidpassage 3095 is adapted to convey fluidic materials such as, forexample, water, drilling mud, cement, epoxy, or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The first inner sealing mandrel 3020 further preferably includes fluidpassages 3110 that are adapted to convey fluidic materials from thefluid passage 3095 into the pressure chambers of the hydraulic slips3025. In this manner, the slips 3025 are activated upon thepressurization of the fluid passage 3095 into contact with the insidesurface of the casing 3075. In a preferred embodiment, the fluidpassages 3110 are adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling fluids or lubricants atoperating pressures and flow rates ranging from about 0 to 9,000 psi and0 to 3,000 gallons/minute.

The first inner sealing mandrel 3020 further preferably includes fluidpassages 3115 that are adapted to convey fluidic materials from thefluid passage 3095 into the first pressure chamber 3175 defined by thefirst upper sealing head 3030, the first lower sealing head 3035, thefirst inner sealing mandrel 3020, and the first outer sealing mandrel3040. During operation of the apparatus 3000, pressurization of thepressure chamber 3175 causes the first upper sealing head 3030, thefirst outer sealing mandrel 3040, the second upper sealing head 3050,the second outer sealing mandrel 3060, and the expansion cone 3070 tomove in an axial direction.

The slips 3025 are coupled to the outside surface of the first innersealing mandrel 3020. During operation of the apparatus 3000, the slips3025 are activated upon the pressurization of the fluid passage 3095into contact with the inside surface of the casing 3075. In this manner,the slips 3025 maintain the casing 3075 in a substantially stationaryposition.

The slips 3025 preferably include fluid passages 3125, pressure chambers3130, spring bias 3135, and slip members 3140. The slips 3025 maycomprise any number of conventional commercially available hydraulicslips such as, for example, RTTS packer tungsten carbide hydraulic slipsor Model 3L retrievable bridge plug with hydraulic slips. In a preferredembodiment, the slips 3025 comprise RTTS packer tungsten carbidehydraulic slips available from Halliburton Energy Services in order tooptimally provide resistance to axial movement of the casing 3075 duringthe expansion process.

The first upper sealing head 3030 is coupled to the first outer sealingmandrel 3040, the second upper sealing head 3050, the second outersealing mandrel 3060, and the expansion cone 3070. The first uppersealing head 3030 is also movably coupled to the outer surface of thefirst inner sealing mandrel 3020 and the inner surface of the casing3075. In this manner, the first upper sealing head 3030, the first outersealing mandrel 3040, the second upper sealing head 3050, the secondouter sealing mandrel 3060, and the expansion cone 3070 reciprocate inthe axial direction.

The radial clearance between the inner cylindrical surface of the firstupper sealing head 3030 and the outer surface of the first inner sealingmandrel 3020 may range, for example, from about 0.0025 to 0.05 inches.In a preferred embodiment, the radial clearance between the innercylindrical surface of the first upper sealing head 3030 and the outersurface of the first inner sealing mandrel 3020 ranges from about 0.005to 0.01 inches in order to optimally provide minimal radial clearance.The radial clearance between the outer cylindrical surface of the firstupper sealing head 3030 and the inner surface of the casing 3075 mayrange, for example, from about 0.025 to 0.375 inches. In a preferredembodiment, the radial clearance between the outer cylindrical surfaceof the first upper sealing head 3030 and the inner surface of the casing3075 ranges from about 0.025 to 0.125 inches in order to optimallyprovide stabilization for the expansion cone 3070 during the expansionprocess.

The first upper sealing head 3030 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The firstupper sealing head 3030 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, or othersimilar high strength materials. In a preferred embodiment, the firstupper sealing head 3030 is fabricated from stainless steel in order tooptimally provide high strength, corrosion resistance, and low frictionsurfaces. The inner surface of the first upper sealing head 3030preferably includes one or more annular sealing members 3145 for sealingthe interface between the first upper sealing head 3030 and the firstinner sealing mandrel 3020. The sealing members 3145 may comprise anynumber of conventional commercially available annular sealing memberssuch as, for example, o-rings, polypak seals or metal spring energizedseals. In a preferred embodiment, the sealing members 3145 comprisepolypak seals available from Parker seals in order to optimally providesealing for a long axial stroke.

In a preferred embodiment, the first upper sealing head 3030 includes ashoulder 3150 for supporting the first upper sealing head 3030, firstouter sealing mandrel 3040, second upper sealing head 3050, second outersealing mandrel 3060, and expansion cone 3070 on the first lower sealinghead 3035.

The first upper sealing head 3030 may be coupled to the first outersealing mandrel 3040 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, or a standard threaded connection. In a preferredembodiment, the first upper sealing head 3030 is removably coupled tothe first outer sealing mandrel 3040 by a standard threaded connection.In a preferred embodiment, the mechanical coupling between the firstupper sealing head 3030 and the first outer sealing mandrel 3040includes one or more sealing members 3155 for fluidicly sealing theinterface between the first upper sealing head 3030 and the first outersealing mandrel 3040. The sealing members 3155 may comprise any numberof conventional commercially available sealing members such as, forexample, o-rings, polypak seals, or metal spring energized seals. In apreferred embodiment, the sealing members 3155 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

The first lower sealing head 3035 is coupled to the first inner sealingmandrel 3020 and the second inner sealing mandrel 3045. The first lowersealing head 3035 is also movably coupled to the inner surface of thefirst outer sealing mandrel 3040. In this manner, the first uppersealing head 3030, first outer sealing mandrel 3040, second uppersealing head 3050, second outer sealing mandrel 3060, and expansion cone3070 reciprocate in the axial direction. The radial clearance betweenthe outer surface of the first lower sealing head 3035 and the innersurface of the first outer sealing mandrel 3040 may range, for example,from about 0.0025 to 0.05 inches. In a preferred embodiment, the radialclearance between the outer surface of the first lower sealing head 3035and the inner surface of the outer sealing mandrel 3040 ranges fromabout 0.005 to 0.01 inches in order to optimally provide minimal radialclearance.

The first lower sealing head 3035 preferably comprises an annular memberhaving substantially cylindrical inner and outer surfaces. The firstlower sealing head 3035 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the first lower sealing head 3035 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces. The outer surface of the firstlower sealing head 3035 preferably includes one or more annular sealingmembers 3160 for sealing the interface between the first lower sealinghead 3035 and the first outer sealing mandrel 3040. The sealing members3160 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals, ormetal spring energized seals. In a preferred embodiment, the sealingmembers 3160 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for a long axial stroke.

The first lower sealing head 3035 may be coupled to the first innersealing mandrel 3020 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection or a standardthreaded connection. In a preferred embodiment, the first lower sealinghead 3035 is removably coupled to the first inner sealing mandrel 3020by a standard threaded connection. In a preferred embodiment, themechanical coupling between the first lower sealing head 3035 and thefirst inner sealing mandrel 3020 includes one or more sealing members3165 for fluidicly sealing the interface between the first lower sealinghead 3035 and the first inner sealing mandrel 3020. The sealing members3165 may comprise any number of conventional commercially availablesealing members such as, for example, o-rings, polypak seals, or metalspring energized seals. In a preferred embodiment, the sealing members3165 comprise polypak seals available from Parker Seals in order tooptimally provide sealing for a long axial stroke length.

The first lower sealing head 3035 may be coupled to the second innersealing mandrel 3045 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection or a standardthreaded connection. In a preferred embodiment, the first lower sealinghead 3035 is removably coupled to the second inner sealing mandrel 3045by a standard threaded connection. In a preferred embodiment, themechanical coupling between the first lower sealing head 3035 and thesecond inner sealing mandrel 3045 includes one or more sealing members3170 for fluidicly sealing the interface between the first lower sealinghead 3035 and the second inner sealing mandrel 3045. The sealing members3170 may comprise any number of conventional commercially availablesealing members such as, for example, o-rings, polypak seals or metalspring energized seals. In a preferred embodiment, the sealing members3170 comprise polypak seals available from Parker Seals in order tooptimally provide sealing for a long axial stroke.

The first outer sealing mandrel 3040 is coupled to the first uppersealing head 3030 and the second upper sealing head 3050. The firstouter sealing mandrel 3040 is also movably coupled to the inner surfaceof the casing 3075 and the outer surface of the first lower sealing head3035. In this manner, the first upper sealing head 3030, first outersealing mandrel 3040, second upper sealing head 3050, second outersealing mandrel 3060, and the expansion cone 3070 reciprocate in theaxial direction. The radial clearance between the outer surface of thefirst outer sealing mandrel 3040 and the inner surface of the casing3075 may range, for example, from about 0.025 to 0.375 inches. In apreferred embodiment, the radial clearance between the outer surface ofthe first outer sealing mandrel 3040 and the inner surface of the casing3075 ranges from about 0.025 to 0.125 inches in order to optimallyprovide stabilization for the expansion cone 3070 during the expansionprocess. The radial clearance between the inner surface of the firstouter sealing mandrel 3040 and the outer surface of the first lowersealing head 3035 may range, for example, from about 0.005 to 0.125inches. In a preferred embodiment, the radial clearance between theinner surface of the first outer sealing mandrel 3040 and the outersurface of the first lower sealing head 3035 ranges from about 0.005 to0.01 inches in order to optimally provide minimal radial clearance.

The first outer sealing mandrel 3040 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thefirst outer sealing mandrel 3040 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the first outer sealing mandrel 3040 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces.

The first outer sealing mandrel 3040 may be coupled to the first uppersealing head 3030 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection or a standardthreaded connection. In a preferred embodiment, the first outer sealingmandrel 3040 is removably coupled to the first upper sealing head 3030by a standard threaded connection. In a preferred embodiment, themechanical coupling between the first outer sealing mandrel 3040 and thefirst upper sealing head 3030 includes one or more sealing members 3180for sealing the interface between the first outer sealing mandrel 3040and the first upper sealing head 3030. The sealing members 3180 maycomprise any number of conventional commercially available sealingmembers such as, for example, o-rings, polypak seals or metal springenergized seals. In a preferred embodiment, the sealing members 3180comprise polypak seals available from Parker Seals in order to optimallyprovide sealing for a long axial stroke.

The first outer sealing mandrel 3040 may be coupled to the second uppersealing head 3050 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection, or a standardthreaded connection. In a preferred embodiment, the first outer sealingmandrel 3040 is removably coupled to the second upper sealing head 3050by a standard threaded connection. In a preferred embodiment, themechanical coupling between the first outer sealing mandrel 3040 and thesecond upper sealing head 3050 includes one or more sealing members 3185for sealing the interface between the first outer sealing mandrel 3040and the second upper sealing head 3050. The sealing members 3185 maycomprise any number of conventional commercially available sealingmembers such as, for example, o-rings, polypak seals or metal springenergized seals. In a preferred embodiment, the sealing members 8185comprise polypak seals available from Parker Seals in order to optimallyprovide sealing for a long axial stroke.

The second inner sealing mandrel 3045 is coupled to the first lowersealing head 3035 and the second lower sealing head 3055. The secondinner sealing mandrel 3045 preferably comprises a substantially hollowtubular member or members. The second inner sealing mandrel 3045 may befabricated from any number of conventional commercially availablematerials such as, for example, oilfield country tubular goods, lowalloy steel, carbon steel, stainless steel or other similar highstrength materials. In a preferred embodiment, the second inner sealingmandrel 3045 is fabricated from stainless steel in order to optimallyprovide high strength, corrosion resistance, and low friction surfaces.

The second inner sealing mandrel 3045 may be coupled to the first lowersealing head 3035 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection or a standardthreaded connection. In a preferred embodiment, the second inner sealingmandrel 3045 is removably coupled to the first lower sealing head 3035by a standard threaded connection. The second inner sealing mandrel 3045may be coupled to the second lower sealing head 3055 using any number ofconventional commercially available mechanical couplings such as, forexample, drillpipe connection, oilfield country tubular goods specialtytype threaded connection, ratchet-latch type connection, or a standardthreaded connection. In a preferred embodiment, the second inner sealingmandrel 3045 is removably coupled to the second lower sealing head 3055by a standard threaded connection.

The second inner sealing mandrel 3045 preferably includes a fluidpassage 3100 that is adapted to convey fluidic materials from the fluidpassage 3095 into the fluid passage 3105. In a preferred embodiment, thefluid passage 3100 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The second inner sealing mandrel 3045 further preferably includes fluidpassages 3120 that are adapted to convey fluidic materials from thefluid passage 3100 into the second pressure chamber 3190 defined by thesecond upper sealing head 3050, the second lower sealing head 3055, thesecond inner sealing mandrel 3045, and the second outer sealing mandrel3060. During operation of the apparatus 3000, pressurization of thesecond pressure chamber 3190 causes the first upper sealing head 3030,the first outer sealing mandrel 3040, the second upper sealing head3050, the second outer sealing mandrel 3060, and the expansion cone 3070to move in an axial direction.

The second upper sealing head 3050 is coupled to the first outer sealingmandrel 3040 and the second outer sealing mandrel 3060. The second uppersealing head 3050 is also movably coupled to the outer surface of thesecond inner sealing mandrel 3045 and the inner surface of the casing3075. In this manner, the second upper sealing head 3050 reciprocates inthe axial direction. The radial clearance between the inner cylindricalsurface of the second upper sealing head 3050 and the outer surface ofthe second inner sealing mandrel 3045 may range, for example, from about0.0025 to 0.05 inches. In a preferred embodiment, the radial clearancebetween the inner cylindrical surface of the second upper sealing head3050 and the outer surface of the second inner sealing mandrel 3045ranges from about 0.005 to 0.01 inches in order to optimally provideminimal radial clearance. The radial clearance between the outercylindrical surface of the second upper sealing head 3050 and the innersurface of the casing 3075 may range, for example, from about 0.025 to0.375 inches. In a preferred embodiment, the radial clearance betweenthe outer cylindrical surface of the second upper sealing head 3050 andthe inner surface of the casing 3075 ranges from about 0.025 to 0.125inches in order to optimally provide stabilization for the expansioncone 3070 during the expansion process.

The second upper sealing head 3050 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thesecond upper sealing head 3050 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the second upper sealing head 3050 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces. The inner surface of the secondupper sealing head 3050 preferably includes one or more annular sealingmembers 3195 for sealing the interface between the second upper sealinghead 3050 and the second inner sealing mandrel 3045. The sealing members3195 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals ormetal spring energized seals. In a preferred embodiment, the sealingmembers 3195 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for a long axial stroke.

In a preferred embodiment, the second upper sealing head 3050 includes ashoulder 3200 for supporting the first upper sealing head 3030, firstouter sealing mandrel 3040, second upper sealing head 3050, second outersealing mandrel 3060, and expansion cone 3070 on the second lowersealing head 3055.

The second upper sealing head 3050 may be coupled to the first outersealing mandrel 3040 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, ratchet-latch type threaded connection, or a standardthreaded connection. In a preferred embodiment, the second upper sealinghead 3050 is removably coupled to the first outer sealing mandrel 3040by a standard threaded connection. In a preferred embodiment, themechanical coupling between the second upper sealing head 3050 and thefirst outer sealing mandrel 3040 includes one or more sealing members3185 for fluidicly sealing the interface between the second uppersealing head 3050 and the first outer sealing mandrel 3040. The secondupper sealing head 3050 may be coupled to the second outer sealingmandrel 3060 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection,oilfield country tubular goods specialty type threaded connection,ratchet-latch type threaded connection, or a standard threadedconnection. In a preferred embodiment, the second upper sealing head3050 is removably coupled to the second outer sealing mandrel 3060 by astandard threaded connection. In a preferred embodiment, the mechanicalcoupling between the second upper sealing head 3050 and the second outersealing mandrel 3060 includes one or more sealing members 3205 forfluidicly sealing the interface between the second upper sealing head3050 and the second outer sealing mandrel 3060.

The second lower sealing head 3055 is coupled to the second innersealing mandrel 3045 and the load mandrel 3065. The second lower sealinghead 3055 is also removably coupled to the inner surface of the secondouter sealing mandrel 3060. In this manner, the first upper sealing head3030, first outer sealing mandrel 3040, second upper sealing mandrel3050, second outer sealing mandrel 3060, and expansion cone 3070reciprocate in the axial direction. The radial clearance between theouter surface of the second lower sealing head 3055 and the innersurface of the second outer sealing mandrel 3060 may range, for example,from about 0.0025 to 0.05 inches. In a preferred embodiment, the radialclearance between the outer surface of the second lower sealing head3055 and the-inner surface of the second outer sealing mandrel 3060ranges from about 0.005 to 0.01 inches in order to optimally provideminimal radial clearance.

The second lower sealing head 3055 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thesecond lower sealing head 3055 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel, or other similar high strength materials. In a preferredembodiment, the second lower sealing head 3055 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces. The outer surface of the secondlower sealing head 3055 preferably includes one or more annular sealingmembers 3210 for sealing the interface between the second lower sealinghead 3055 and the second outer sealing mandrel 3060. The sealing members3210 may comprise any number of conventional commercially availableannular sealing members such as, for example, o-rings, polypak seals, ormetal spring energized seals. In a preferred embodiment, the sealingmembers 3210 comprise polypak seals available from Parker Seals in orderto optimally provide sealing for long axial strokes.

The second lower sealing head 3055 may be coupled to the second innersealing mandrel 3045 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, or a standard threaded connection. In a preferredembodiment, the second lower sealing head 3055 is removably coupled tothe second inner sealing mandrel 3045 by a standard threaded connection.In a preferred embodiment, the mechanical coupling between the lowersealing head 3055 and the second inner sealing mandrel 3045 includes oneor more sealing members 3215 for fluidicly sealing the interface betweenthe second lower sealing head 3055 and the second inner sealing mandrel3045. The sealing members 3215 may comprise any number of conventionalcommercially available sealing members such as, for example, o-rings,polypak seals or metal spring energized seals. In a preferredembodiment, the sealing members 3215 comprise polypak seals availablefrom Parker Seals in order to optimally provide sealing for long axialstrokes.

The second lower sealing head 3055 may be coupled to the load mandrel3065 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnection. In a preferred embodiment, the second lower sealing head3055 is removably coupled to the load mandrel 3065 by a standardthreaded connection. In a preferred embodiment, the mechanical couplingbetween the second lower sealing head 3055 and the load mandrel 3065includes one or more sealing members 3220 for fluidicly sealing theinterface between the second lower sealing head 3055 and the loadmandrel 3065. The sealing members 3220 may comprise any number ofconventional commercially available sealing members such as, forexample, o-rings, polypak seals or metal spring energized seals. In apreferred embodiment, the sealing members 3220 comprise polypak sealsavailable from Parker Seals in order to optimally provide sealing for along axial stroke.

In a preferred embodiment, the second lower sealing head 3055 includes athroat passage 3225 fluidicly coupled between the fluid passages 3100and 3105. The throat passage 3225 is preferably of reduced size and isadapted to receive and engage with a plug 3230, or other similar device.In this manner, the fluid passage 3100 is fluidicly isolated from thefluid passage 3105. In this manner, the pressure chambers 3175 and 3190are pressurized. Furthermore, the placement of the plug 3230 in thethroat passage 3225 also pressurizes the pressure chambers 3130 of thehydraulic slips 3025.

The second outer sealing mandrel 3060 is coupled to the second uppersealing head 3050 and the expansion cone 3070. The second outer sealingmandrel 3060 is also movably coupled to the inner surface of the casing3075 and the outer surface of the second lower sealing head 3055. Inthis manner, the first upper sealing head 3030, first outer sealingmandrel 3040, second upper sealing head 3050, second outer sealingmandrel 3060, and the expansion cone 3070 reciprocate in the axialdirection. The radial clearance between the outer surface of the secondouter sealing mandrel 3060 and the inner surface of the casing 3075 mayrange, for example, from about 0.025 to 0.375 inches. In a preferredembodiment, the radial clearance between the outer surface of the secondouter sealing mandrel 3060 and the inner surface of the casing 3075ranges from about 0.025 to 0.125 inches in order to optimally providestabilization for the expansion cone 3070 during the expansion process.The radial clearance between the inner surface of the second outersealing mandrel 3060 and the outer surface of the second lower sealinghead 3055 may range, for example, from about 0.0025 to 0.05 inches. In apreferred embodiment, the radial clearance between the inner surface ofthe second outer sealing mandrel 3060 and the outer surface of thesecond lower sealing head 3055 ranges from about 0.005 to 0.01 inches inorder to optimally provide minimal radial clearance.

The second outer sealing mandrel 3060 preferably comprises an annularmember having substantially cylindrical inner and outer surfaces. Thesecond outer sealing mandrel 3060 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel, stainlesssteel or other similar high strength materials. In a preferredembodiment, the second outer sealing mandrel 3060 is fabricated fromstainless steel in order to optimally provide high strength, corrosionresistance, and low friction surfaces.

The second outer sealing mandrel 3060 may be coupled to the second uppersealing head 3050 using any number of conventional commerciallyavailable mechanical couplings such as, for example, drillpipeconnection, oilfield country tubular goods specialty type threadedconnection, or a standard threaded connection. In a preferredembodiment, the outer sealing mandrel 3060 is removably coupled to thesecond upper sealing head 3050 by a standard threaded connection. Thesecond outer sealing mandrel 3060 may be coupled to the expansion cone3070 using any number of conventional commercially available mechanicalcouplings such as, for example, drillpipe connection, oilfield countrytubular goods specialty type threaded connection, or a standard threadedconnection. In a preferred embodiment, the second outer sealing mandrel3060 is removably coupled to the expansion cone 3070 by a standardthreaded connection.

The first upper sealing head 3030, the first lower sealing head 3035,the first inner sealing mandrel 3020, and the first outer sealingmandrel 3040 together define the first pressure chamber 3175. The secondupper sealing head 3050, the second lower sealing head 3055, the secondinner sealing mandrel 3045, and the second outer sealing mandrel 3060together define the second pressure-chamber 3190. The first and secondpressure chambers, 3175 and 3190, are fluidicly coupled to the passages,3095 and 3100, via one or more passages, 3115 and 3120. During operationof the apparatus 3000, the plug 3230 engages with the throat passage3225 to fluidicly isolate the fluid passage 3100 from the fluid passage3105. The pressure chambers, 3175 and 3190, are then pressurized whichin turn causes the first upper sealing head 3030, the first outersealing mandrel 3040, the second upper sealing head 3050, the secondouter sealing mandrel 3060, and expansion cone 3070 to reciprocate inthe axial direction. The axial motion of the expansion cone 3070 in turnexpands the casing 3075 in the radial direction. The use of a pluralityof pressure chambers, 3175 and 3190, effectively multiplies theavailable driving force for the expansion cone 3070.

The load mandrel 3065 is coupled to the second lower sealing head 3055.The load mandrel 3065 preferably comprises an annular member havingsubstantially cylindrical inner and outer surfaces. The load mandrel3065 may be fabricated from any number of conventional commerciallyavailable materials such as, for example, oilfield country tubulargoods, low alloy steel, carbon steel, stainless steel or other similarhigh strength materials. In a preferred embodiment, the load mandrel3065 is fabricated from stainless steel in order to optimally providehigh strength, corrosion resistance, and low friction surfaces.

The load mandrel 3065 may be coupled to the lower sealing head 3055using any number of conventional commercially available mechanicalcouplings such as, for example, epoxy, cement, water, drilling mud, orlubricants. In a preferred embodiment, the load mandrel 3065 isremovably coupled to the lower sealing head 3055 by a standard threadedconnection.

The load mandrel 3065 preferably includes a fluid passage 3105 that isadapted to convey fluidic materials from the fluid passage 3100 to theregion outside of the apparatus 3000. In a preferred embodiment, thefluid passage 3105 is adapted to convey fluidic materials such as, forexample, cement, epoxy, water, drilling mud or lubricants at operatingpressures and flow rates ranging from about 0 to 9,000 psi and 0 to3,000 gallons/minute.

The expansion cone 3070 is coupled to the second outer sealing mandrel3060. The expansion cone 3070 is also movably coupled to the innersurface of the casing 3075. In this manner, the first upper sealing head3030, first outer sealing mandrel 3040, second upper sealing head 3050,second outer sealing mandrel 3060, and the expansion cone 3070reciprocate in the axial direction. The reciprocation of the expansioncone 3070 causes the casing 3075 to expand in the radial direction.

The expansion cone 3070 preferably comprises an annular member havingsubstantially cylindrical inner and conical outer surfaces. The outsideradius of the outside conical surface may range, for example, from about2 to 34 inches. In a preferred embodiment, the outside radius of theoutside conical surface ranges from about 3 to 28 inches in order tooptimally provide an expansion cone 3070 for expanding typical casings.The axial length of the expansion cone 3070 may range, for example, fromabout 2 to 8 times the maximum outer diameter of the expansion cone3070. In a preferred embodiment, the axial length of the expansion cone3070 ranges from about 3 to 5 times the maximum outer diameter of theexpansion cone 3070 in order to optimally provide stabilization andcentralization of the expansion cone 3070 during the expansion process.In a particularly preferred embodiment, the maximum outside diameter ofthe expansion cone 3070 is between about 95 to 99% of the insidediameter of the existing wellbore that the casing 3075 will be joinedwith. In a preferred embodiment, the angle of attack of the expansioncone 3070 ranges from about 5 to 30 degrees in order to optimallybalance the frictional forces with the radial expansion forces.

The expansion cone 3070 may be fabricated from any number ofconventional commercially available materials such as, for example,machine tool steel, nitride steel, titanium, tungsten carbide, ceramics,or other similar high strength materials. In a preferred embodiment, theexpansion cone 3070 is fabricated from D2 machine tool steel in order tooptimally provide high strength and resistance to wear and galling. In aparticularly preferred embodiment, the outside surface of the expansioncone 3070 has a surface hardness ranging from about 58 to 62 Rockwell Cin order to optimally provide high strength and resistance to wear andgalling.

The expansion cone 3070 may be coupled to the second outside sealingmandrel 3060 using any number of conventional commercially availablemechanical couplings such as, for example, drillpipe connection,oilfield country tubular goods specialty type threaded connection,ratchet-latch type connection or a standard threaded connection. In apreferred embodiment, the expansion cone 3070 is coupled to the secondoutside sealing mandrel 3060 using a standard threaded connection inorder to optimally provide high strength and easy disassembly.

The casing 3075 is removably coupled to the slips 3025 and the expansioncone 3070. The casing 3075 preferably comprises a tubular member. Thecasing 3075 may be fabricated from any number of conventionalcommercially available materials such as, for example, slotted tubulars,oilfield country tubular goods, carbon steel, low alloy steel, stainlesssteel, or other similar high strength materials. In a preferredembodiment, the casing 3075 is fabricated from oilfield country tubulargoods available from various foreign and domestic steel mills in orderto optimally provide high strength.

In a preferred embodiment, the upper end 3235 of the casing 3075includes a thin wall section 3240 and an outer annular sealing member3245. In a preferred embodiment, the wall thickness of the thin wallsection 3240 is about 50 to 100% of the regular wall thickness of thecasing 3075. In this manner, the upper end 3235 of the casing 3075 maybe easily radially expanded and deformed into intimate contact with thelower end of an existing section of wellbore casing. In a preferredembodiment, the lower end of the existing section of casing alsoincludes a thin wall section. In this manner, the radial expansion ofthe thin walled section 3240 of casing 3075 into the thin walled sectionof the existing wellbore casing results in a wellbore casing having asubstantially constant inside diameter.

The annular sealing member 3245 may be fabricated from any number ofconventional commercially available sealing materials such as, forexample, epoxy, rubber, metal or plastic. In a preferred embodiment, theannular sealing member 3245 is fabricated from StrataLock epoxy in orderto optimally provide compressibility and wear resistance. The outsidediameter of the annular sealing member 3245 preferably ranges from about70 to 95% of the inside diameter of the lower section of the wellborecasing that the casing 3075 is joined to. In this manner, after radialexpansion, the annular sealing member 3245 optimally provides a fluidicseal and also preferably optimally provides sufficient frictional forcewith the inside surface of the existing section of wellbore casingduring the radial expansion of the casing 3075 to support the casing3075.

In a preferred embodiment, the lower end 3250 of the casing 3075includes a thin wall section 3255 and an outer annular sealing member3260. In a preferred embodiment, the wall thickness of the thin wallsection 3255 is about 50 to 100% of the regular wall thickness of thecasing 3075. In this manner, the lower end 3250 of the casing 3075 maybe easily expanded and deformed. Furthermore, in this manner, an othersection of casing may be easily joined with the lower end 3250 of thecasing 3075 using a radial expansion process. In a preferred embodiment,the upper end of the other section of casing also includes a thin wallsection. In this manner, the radial expansion of the thin walled sectionof the upper end of the other casing into the thin walled section 3255of the lower end 3250 of the casing 3075 results in a wellbore casinghaving a substantially constant inside diameter.

The upper annular sealing member 3245 may be fabricated from any numberof conventional commercially available sealing materials such as, forexample, epoxy, rubber, metal or plastic. In a preferred embodiment, theupper annular sealing member 3245 is fabricated from Stratalock epoxy inorder to optimally provide compressibility and resistance to wear. Theoutside diameter of the upper annular sealing member 3245 preferablyranges from about 70 to 95% of the inside diameter of the lower sectionof the existing wellbore casing that the casing 3075 is joined to. Inthis manner, after radial expansion, the upper annular sealing member3245 preferably provides a fluidic seal and also preferably providessufficient frictional force with the inside wall of the wellbore duringthe radial expansion of the casing 3075 to support the casing 3075.

The lower annular sealing member 3260 may be fabricated from any numberof conventional commercially available sealing materials such as, forexample, epoxy, rubber, metal or plastic. In a preferred embodiment, thelower annular sealing member 3260 is fabricated from StrataLock epoxy inorder to optimally provide compressibility and resistance to wear. Theoutside diameter of the lower annular sealing member 3260 preferablyranges from about 70 to 95% of the inside diameter of the lower sectionof the existing wellbore casing that the casing 3075 is joined to. Inthis manner, the lower annular sealing member 3260 preferably provides afluidic seal and also preferably provides sufficient frictional forcewith the inside wall of the wellbore during the radial expansion of thecasing 3075 to support the casing 3075.

During operation, the apparatus 3000 is preferably positioned in awellbore with the upper end 3235 of the casing 3075 positioned in anoverlapping relationship with the lower end of an existing wellborecasing. In a particularly preferred embodiment, the thin wall section3240 of the casing 3075 is positioned in opposing overlapping relationwith the thin wall section and outer annular sealing member of the lowerend of the existing section of wellbore casing. In this manner, theradial expansion of the casing 3075 will compress the thin wall sectionsand annular compressible members of the upper end 3235 of the casing3075 and the lower end of the existing wellbore casing into intimatecontact. During the positioning of the apparatus 3000 in the wellbore,the casing 3000 is preferably supported by the expansion cone 3070.

After positioning the apparatus 3000, a first fluidic material is thenpumped into the fluid passage 3080. The first fluidic material maycomprise any number of conventional commercially available materialssuch as, for example, drilling mud, water, epoxy, cement, slag mix orlubricants. In a preferred embodiment, the first fluidic materialcomprises a hardenable fluidic sealing material such as, for example,cement, epoxy, or slag mix in order to optimally provide a hardenableouter annular body around the expanded casing 3075.

The first fluidic material may be pumped into the fluid passage 3080 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thefirst fluidic material is pumped into the fluid passage 3080 atoperating pressures and flow rates ranging from about 0 to 3,500 psi and0 to 1,200 gallons/minute in order to optimally provide operatingefficiency.

The first fluidic material pumped into the fluid passage 3080 passesthrough the fluid passages 3085, 3090, 3095, 3100, and 3105 and thenoutside of the apparatus 3000. The first fluidic material thenpreferably fills the annular region between the outside of the apparatus3000 and the interior walls of the wellbore.

The plug 3230 is then introduced into the fluid passage 3080. The plug3230 lodges in the throat passage 3225 and fluidicly isolates and blocksoff the fluid passage 3100. In a preferred embodiment, a couple ofvolumes of a non-hardenable fluidic material are then pumped into thefluid passage 3080 in order to remove any hardenable fluidic materialcontained within and to ensure that none of the fluid passages areblocked.

A second fluidic material is then pumped into the fluid passage 3080.The second fluidic material may comprise any number of conventionalcommercially available materials such as, for example, water, drillinggases, drilling mud or lubricant. In a preferred embodiment, the secondfluidic material comprises a non-hardenable fluidic material such as,for example, water, drilling mud, drilling gases, or lubricant in orderto optimally provide pressurization of the pressure chambers 3175 and3190.

The second fluidic material may be pumped into the fluid passage 3080 atoperating pressures and flow rates ranging, for example, from about 0 to4,500 psi and 0 to 4,500 gallons/minute. In a preferred embodiment, thesecond fluidic material is pumped into the fluid passage 3080 atoperating pressures and flow rates ranging from about 0 to 3,500 psi and0 to 1,200 gallons/minute in order to optimally provide operationalefficiency.

The second fluidic material pumped into the fluid passage 3080 passesthrough the fluid passages 3085, 3090, 3095, 3100 and into the pressurechambers 3130 of the slips 3025, and into the pressure chambers 3175 and3190. Continued pumping of the second fluidic material pressurizes thepressure chambers 3130, 3175, and 3190.

The pressurization of the pressure chambers 3130 causes the hydraulicslip members 3140 to expand in the radial direction and grip theinterior surface of the casing 3075. The casing 3075 is then preferablymaintained in a substantially stationary position.

The pressurization of the pressure chambers 3175 and 3190 cause thefirst upper sealing head 3030, first outer sealing mandrel 3040, secondupper sealing head 3050, second outer sealing mandrel 3060, andexpansion cone 3070 to move in an axial direction relative to the casing3075. In this manner, the expansion cone 3070 will cause the casing 3075to expand in the radial direction, beginning with the lower end 3250 ofthe casing 3075.

During the radial expansion process, the casing 3075 is prevented frommoving in an upward direction by the slips 3025. A length of the casing3075 is then expanded in the radial direction through the pressurizationof the pressure chambers 3175 and 3190. The length of the casing 3075that is expanded during the expansion process will be proportional tothe stroke length of the first upper sealing head 3030, first outersealing mandrel 3040, second upper sealing head 3050, and expansion cone3070.

Upon the completion of a stroke, the operating pressure of the secondfluidic material is reduced and the first upper sealing head 3030, firstouter sealing mandrel 3040, second upper sealing head 3050, second outersealing mandrel 3060, and expansion cone 3070 drop to their restpositions with the casing 3075 supported by the expansion cone 3070. Thereduction in the operating pressure of the second fluidic material alsocauses the spring bias 3135 of the slips 3025 to pull the slip members3140 away from the inside walls of the casing 3075.

The position of the drillpipe 3075 is preferably adjusted throughout theradial expansion process in order to maintain the overlappingrelationship between the thin walled sections of the lower end of theexisting wellbore casing and the upper end of the casing 3235. In apreferred embodiment, the stroking of the expansion cone 3070 is thenrepeated, as necessary, until the thin walled section 3240 of the upperend 3235 of the casing 3075 is expanded into the thin walled section ofthe lower end of the existing wellbore casing. In this manner, awellbore casing is formed including two adjacent sections of casinghaving a substantially constant inside diameter. This process may thenbe repeated for the entirety of the wellbore to provide a wellborecasing thousands of feet in length having a substantially constantinside diameter.

In a preferred embodiment, during the final stroke of the expansion cone3070, the slips 3025 are positioned as close as possible to the thinwalled section 3240 of the upper end 3235 of the casing 3075 in orderminimize slippage between the casing 3075 and the existing wellborecasing at the end of the radial expansion process. Alternatively, or inaddition, the outside diameter of the upper annular sealing member 3245is selected to ensure sufficient interference fit with the insidediameter of the lower end of the existing casing to prevent axialdisplacement of the casing 3075 during the final stroke. Alternatively,or in addition, the outside diameter of the lower annular sealing member3260 is selected to provide an interference fit with the inside walls ofthe wellbore at an earlier point in the radial expansion process so asto prevent further axial displacement of the casing 3075. In this finalalternative, the interference fit is preferably selected to permitexpansion of the casing 3075 by pulling the expansion cone 3070 out ofthe wellbore, without having to pressurize the pressure chambers 3175and 3190.

During the radial expansion process, the pressurized areas of theapparatus 3000 are preferably limited to the fluid passages 3080, 3085,3090, 3095, 3100, 3110, 3115, 3120, the pressure chambers 3130 withinthe slips 3025, and the pressure chambers 3175 and 3190. No fluidpressure acts directly on the casing 3075. This permits the use ofoperating pressures higher than the casing 3075 could normallywithstand.

Once the casing 3075 has been completely expanded off of the expansioncone 3070, the remaining portions of the apparatus 3000 are removed fromthe wellbore. In a preferred embodiment, the contact pressure betweenthe deformed thin wall sections and compressible annular members of thelower end of the existing casing and the upper end 3235 of the casing3075 ranges from about 400 to 10,000 psi in order to optimally supportthe casing 3075 using the existing wellbore casing.

In this manner, the casing 3075 is radially expanded into contact withan existing section of casing by pressurizing the interior fluidpassages 3080, 3085, 3090, 3095, 3100, 3110, 3115, and 3120, thepressure chambers 3130 of the slips 3025 and the pressure chambers 3175and 3190 of the apparatus 3000.

In a preferred embodiment, as required, the annular body of hardenablefluidic material is then allowed to cure to form a rigid outer annularbody about the expanded casing 3075. In the case where the casing 3075is slotted, the cured fluidic material preferably permeates and envelopsthe expanded casing 3075. The resulting new section of wellbore casingincludes the expanded casing 3075 and the rigid outer annular body. Theoverlapping joint between the pre-existing wellbore casing and theexpanded casing 3075 includes the deformed thin wall sections and thecompressible outer annular bodies. The inner diameter of the resultingcombined wellbore casings is substantially constant. In this manner, amono-diameter wellbore casing is formed. This process of expandingoverlapping tubular members having thin wall end portions withcompressible annular bodies into contact can be repeated for the entirelength of a wellbore. In this manner, a mono-diameter wellbore casingcan be provided for thousands of feet in a subterranean formation.

In a preferred embodiment, as the expansion cone 3070 nears the upperend 3235 of the casing 3075, the operating flow rate of the secondfluidic material is reduced in order to minimize shock to the apparatus3000. In an alternative embodiment, the apparatus 3000 includes a shockabsorber for absorbing the shock created by the completion of the radialexpansion of the casing 3075.

In a preferred embodiment, the reduced operating pressure of the secondfluidic material ranges from about 100 to 1,000 psi as the expansioncone 3070 nears the end of the casing 3075 in order to optimally providereduced axial movement and velocity of the expansion cone 3070. In apreferred embodiment, the operating pressure of the second fluidicmaterial is reduced during the return stroke of the apparatus 3000 tothe range of about 0 to 500 psi in order minimize the resistance to themovement of the expansion cone 3070 during the return stroke. In apreferred embodiment, the stroke length of the apparatus 3000 rangesfrom about 10 to 45 feet in order to optimally provide equipment thatcan be easily handled by typical oil well rigging equipment and alsominimize the frequency at which the apparatus 3000 must be re-stroked.

In an alternative embodiment, at least a portion of one or both of theupper sealing heads, 3030 and 3050, includes an expansion cone forradially expanding the casing 3075 during operation of the apparatus3000 in order to increase the surface area of the casing 3075 acted uponduring the radial expansion process. In this manner, the operatingpressures can be reduced.

Alternatively, the apparatus 3000 may be used to join a first section ofpipeline to an existing section of pipeline. Alternatively, theapparatus 3000 may be used to directly line the interior of a wellborewith a casing, without the use of an outer annular layer of a hardenablematerial. Alternatively, the apparatus 3000 may be used to expand atubular support member in a hole.

Referring now to FIG. 21, an apparatus 3330 for isolating subterraneanzones will be described. A wellbore 3305 including a casing 3310 arepositioned in a subterranean formation 3315. The subterranean formation3315 includes a number of productive and non-productive zones, includinga water zone 3320 and a targeted oil sand zone 3325. During explorationof the subterranean formation 3315, the wellbore 3305 may be extended ina well known manner to traverse the various productive andnon-productive zones, including the water zone 3320 and the targeted oilsand zone 3325.

In a preferred embodiment, in order to fluidicly isolate the water zone3320 from the targeted oil sand zone 3325, an apparatus 3330 is providedthat includes one or more sections of solid casing 3335, one or moreexternal seals 3340, one or more sections of slotted casing 3345, one ormore intermediate sections of solid casing 3350, and a solid shoe 3355.

The solid casing 3335 may provide a fluid conduit that transmits fluidsand other materials from one end of the solid casing 3335 to the otherend of the solid casing 3335. The solid casing 3335 may comprise anynumber of conventional commercially available sections of solid tubularcasing such as, for example, oilfield tubulars fabricated from chromiumsteel or fiberglass. In a preferred embodiment, the solid casing 3335comprises oilfield tubulars available from various foreign and domesticsteel mills.

The solid casing 3335 is preferably coupled to the casing 3310. Thesolid casing 3335 may be coupled to the casing 3310 using any number ofconventional commercially available processes such as, for example,welding, slotted and expandable connectors, or expandable solidconnectors. In a preferred embodiment, the solid casing 3335 is coupledto the casing 3310 by using expandable solid connectors. The solidcasing 3335 may comprise a plurality of such solid casings 3335.

The solid casing 3335 is preferably coupled to one more of the slottedcasings 3345. The solid casing 3335 may be coupled to the slotted casing3345 using any number of conventional commercially available processessuch as, for example, welding, or slotted and expandable connectors. Ina preferred embodiment, the solid casing 3335 is coupled to the slottedcasing 3345 by expandable solid connectors.

In a preferred embodiment, the casing 3335 includes one more valvemembers 3360 for controlling the flow of fluids and other materialswithin the interior region of the casing 3335. In an alternativeembodiment, during the production mode of operation, an internal tubularstring with various arrangements of packers, perforated tubing, slidingsleeves, and valves may be employed within the apparatus to providevarious options for commingling and isolating subterranean zones fromeach other while providing a fluid path to the surface.

In a particularly preferred embodiment, the casing 3335 is placed intothe wellbore 3305 by expanding the casing 3335 in the radial directioninto intimate contact with the interior walls of the wellbore 3305. Thecasing 3335 may be expanded in the radial direction using any number ofconventional commercially available methods. In a preferred embodiment,the casing 3335 is expanded in the radial direction using one or more ofthe processes and apparatus described within the present disclosure.

The seals 3340 prevent the passage of fluids and other materials withinthe annular region 3365 between the solid casings 3335 and 3350 and thewellbore 3305. The seals 3340 may comprise any number of conventionalcommercially available sealing materials suitable for sealing a casingin a wellbore such as, for example, lead, rubber or epoxy. In apreferred embodiment, the seals 3340 comprise Stratalock epoxy materialavailable from Halliburton Energy Services.

The slotted casing 3345 permits fluids and other materials to pass intoand out of the interior of the slotted casing 3345 from and to theannular region 3365. In this manner, oil and gas may be produced from aproducing subterranean zone within a subterranean formation. The slottedcasing 3345 may comprise any number of conventional commerciallyavailable sections of slotted tubular casing. In a preferred embodiment,the slotted casing 3345 comprises expandable slotted tubular casingavailable from Petroline in Abeerdeen, Scotland. In a particularlypreferred embodiment, the slotted casing 145 comprises expandableslotted sandscreen tubular casing available from Petroline in Abeerdeen,Scotland.

The slotted casing 3345 is preferably coupled to one or more solidcasing 3335. The slotted casing 3345 may be coupled to the solid casing3335 using any number of conventional commercially available processessuch as, for example, welding, or slotted or solid expandableconnectors. In a preferred embodiment, the slotted casing 3345 iscoupled to the solid casing 3335 by expandable solid connectors.

The slotted casing 3345 is preferably coupled to one or moreintermediate solid casings 3350. The slotted casing 3345 may be coupledto the intermediate solid casing 3350 using any number of conventionalcommercially available processes such as, for example, welding orexpandable solid or slotted connectors. In a preferred embodiment, theslotted casing 3345 is coupled to the intermediate solid casing 3350 byexpandable solid connectors.

The last section of slotted casing 3345 is preferably coupled to theshoe 3355. The last slotted casing 3345 may be coupled to the shoe 3355using any number of conventional commercially available processes suchas, for example, welding or expandable solid or slotted connectors. In apreferred embodiment, the last slotted casing 3345 is coupled to theshoe 3355 by an expandable solid connector.

In an alternative embodiment, the shoe 3355 is coupled directly to thelast one of the intermediate solid casings 3350.

In a preferred embodiment, the slotted casings 3345 are positionedwithin the wellbore 3305 by expanding the slotted casings 3345 in aradial direction into intimate contact with the interior walls of thewellbore 3305. The slotted casings 3345 may be expanded in a radialdirection using any number of conventional commercially availableprocesses. In a preferred embodiment, the slotted casings 3345 areexpanded in the radial direction using one or more of the processes andapparatus disclosed in the present disclosure with reference to FIGS.14a-20.

The intermediate solid casing 3350 permits fluids and other materials topass between adjacent slotted casings 3345. The intermediate solidcasing 3350 may comprise any number of conventional commerciallyavailable sections of solid tubular casing such as, for example,oilfield tubulars fabricated from chromium steel or fiberglass. In apreferred embodiment, the intermediate solid casing 3350 comprisesoilfield tubulars available from foreign and domestic steel mills.

The intermediate solid casing 3350 is preferably coupled to one or moresections of the slotted casing 3345. The intermediate solid casing 3350may be coupled to the slotted casing 3345 using any number ofconventional commercially available processes such as, for example,welding, or solid or slotted expandable connectors. In a preferredembodiment, the intermediate solid casing 3350 is coupled to the slottedcasing 3345 by expandable solid connectors. The intermediate solidcasing 3350 may comprise a plurality of such intermediate solid casing3350.

In a preferred embodiment, each intermediate solid casing 3350 includesone more valve members 3370 for controlling the flow of fluids and othermaterials within the interior region of the intermediate casing 3350. Inan alternative embodiment, as will be recognized by persons havingordinary skill in the art and the benefit of the present disclosure,during the production mode of operation, an internal tubular string withvarious arrangements of packers, perforated tubing, sliding sleeves, andvalves may be employed within the apparatus to provide various optionsfor commingling and isolating subterranean zones from each other whileproviding a fluid path to the surface.

In a particularly preferred embodiment, the intermediate casing 3350 isplaced into the wellbore 3305 by expanding the intermediate casing 3350in the radial direction into intimate contact with the interior walls ofthe wellbore 3305. The intermediate casing 3350 may be expanded in theradial direction using any number of conventional commercially availablemethods.

In an alternative embodiment, one or more of the intermediate solidcasings 3350 may be omitted. In an alternative preferred embodiment, oneor more of the slotted casings 3345 are provided with one or more seals3340.

The shoe 3355 provides a support member for the apparatus 3330. In thismanner, various production and exploration tools may be supported by theshow 3350. The shoe 3350 may comprise any number of conventionalcommercially available shoes suitable for use in a wellbore such as, forexample, cement filled shoe, or an aluminum or composite shoe. In apreferred embodiment, the shoe 3350 comprises an aluminum shoe availablefrom Halliburton. In a preferred embodiment, the shoe 3355 is selectedto provide sufficient strength in compression and tension to permit theuse of high capacity production and exploration tools.

In a particularly preferred embodiment, the apparatus 3330 includes aplurality of solid casings 3335, a plurality of seals 3340, a pluralityof slotted casings 3345, a plurality of intermediate solid casings 3350,and a shoe 3355. More generally, the apparatus 3330 may comprise one ormore solid casings 3335, each with one or more valve members 3360, nslotted casings 3345, n-1 intermediate solid casings 3350, each with oneor more valve members 3370, and a shoe 3355.

During operation of the apparatus 3330, oil and gas may be controllablyproduced from the targeted oil sand zone 3325 using the slotted casings3345. The oil and gas may then be transported to a surface locationusing the solid casing 3335. The use of intermediate solid casings 3350with valve members 3370 permits isolated sections of the zone 3325 to beselectively isolated for production. The seals 3340 permit the zone 3325to be fluidicly isolated from the zone 3320. The seals 3340 furtherpermits isolated sections of the zone 3325 to be fluidicly isolated fromeach other. In this manner, the apparatus 3330 permits unwanted and/ornon-productive subterranean zones to be fluidicly isolated.

In an alternative embodiment, as will be recognized by persons havingordinary skill in the art and also having the benefit of the presentdisclosure, during the production mode of operation, an internal tubularstring with various arrangements of packers, perforated tubing, slidingsleeves, and valves may be employed within the apparatus to providevarious options for commingling and isolating subterranean zones fromeach other while providing a fluid path to the surface.

Referring to FIGS. 22a, 22 b, 22 c and 22 d, an embodiment of anapparatus 3500 for forming a wellbore casing while drilling a wellborewill now be described. In a preferred embodiment, the apparatus 3500includes a support member 3505, a mandrel 3510, a mandrel launcher 3515,a shoe 3520, a tubular member 3525, a mud motor 3530, a drill bit 3535,a first fluid passage 3540, a second fluid passage 3545, a pressurechamber 3550, a third fluid passage 3555, a cup seal 3560, a body oflubricant 3565, seals 3570, and a releasable coupling 3600.

The support member 3505 is coupled to the mandrel 3510. The supportmember 3505 preferably comprises an annular member having sufficientstrength to carry and support the apparatus 3500 within the wellbore3575. In a preferred embodiment, the support member 3505 furtherincludes one or more conventional centralizers (not illustrated) to helpstabilize the apparatus 3500.

The support member 3505 may comprise one or more sections ofconventional commercially available tubular materials such as, forexample, oilfield country tubular goods, low alloy steel, stainlesssteel or carbon steel. In a preferred embodiment, the support member3505 comprises coiled tubing or drillpipe in order to optimally permitthe placement of the apparatus 3500 within a non-vertical wellbore.

In a preferred embodiment, the support member 3505 includes a firstfluid passage 3540 for conveying fluidic materials from a surfacelocation to the fluid passage 3545. In a preferred embodiment, the firstfluid passage 3540 is adapted to convey fluidic materials such as water,drilling mud, cement, epoxy or slag mix at operating pressures and flowrates ranging from about 0 to 10,000 psi and 0 to 3,000 gallons/minute.

The mandrel 3510 is coupled to and supported by the support member 3505.The mandrel 3510 is also coupled to and supports the mandrel launcher3515 and tubular member 3525. The mandrel 3510 is preferably adapted tocontrollably expand in a radial direction. The mandrel 3510 may compriseany number of conventional commercially available mandrels modified inaccordance with the teachings of the present disclosure. In a preferredembodiment, the mandrel 3510 comprises a hydraulic expansion tool asdisclosed in U.S. Pat. No. 5,348,095, the contents of which areincorporated herein by reference, modified in accordance with theteachings of the present disclosure.

In a preferred embodiment, the mandrel 3510 includes one or more conicalsections for expanding the tubular member 3525 in the radial direction.In a preferred embodiment, the outer surfaces of the conical sections ofthe mandrel 3510 have a surface hardness ranging from about 58 to 62Rockwell C in order to optimally radially expand the tubular member3525.

In a preferred embodiment, the mandrel 3510 includes a second fluidpassage 3545 fluidicly coupled to the first fluid passage 3540 and thepressure chamber 3550 for conveying fluidic materials from the firstfluid passage 3540 to the pressure chamber 3550. In a preferredembodiment, the second fluid passage 3545 is adapted to convey fluidicmaterials such as water, drilling mud, cement, epoxy or slag mix atoperating pressures and flow rates ranging from about 0 to 12,000 psiand 0 to 3,500 gallons/minute in order to optimally provide operatingpressure for efficient operation.

The mandrel launcher 3515 is coupled to the tubular member 3525, themandrel 3510, and the shoe 3520. The mandrel launcher 3515 preferablycomprises a tapered annular member that mates with at a portion of atleast one of the conical portions of the outer surface of the mandrel3510. In a preferred embodiment, the wall thickness of the mandrellauncher is less than the wall thickness of the tubular member 3525 inorder to facilitate the initiation of the radial expansion process andfacilitate the placement of the apparatus in openings having tightclearances. In a preferred embodiment, the wall thickness of the mandrellauncher 3515 ranges from about 50 to 100% of the wall thickness of thetubular member 3525 immediately adjacent to the mandrel launcher 3515 inorder to optimally faciliate the radial expansion process and facilitatethe insertion of the apparatus 3500 into wellbore casings and otherareas with tight clearances.

The mandrel launcher 3515 may be fabricated from any number ofconventional commercially available materials such as, for example,oilfield country tubular goods, low alloy steel, carbon steel orstainless steel. In a preferred embodiment, the mandrel launcher 3515 isfabricated from oilfield country tubular goods of higher strength bylower wall thickness than the tubular member 3525 in order to optimallyprovide a smaller container having approximately the same burst strengthas the tubular member 3525.

The shoe 3520 is coupled to the mandrel launcher 3515 and the releasablecoupling 3600. The shoe 3520 preferably comprises a substantiallyannular member. In a preferred embodiment, the shoe 3520 or thereleasable coupling 3600 include a third fluid passage 3555 fluidiclycoupled to the pressure chamber 3550 and the mud motor 3530.

The shoe 3520 may comprise any number of conventional commerciallyavailable shoes such as, for example, cement filled, aluminum orcomposite modified in accordance with the teachings of the presentdisclosure. In a preferred embodiment, the shoe 3520 comprises a highstrength shoe having a burst strength approximately equal to the burststrength of the tubular member 3525 and mandrel launcher 3515. The shoe3520 is preferably coupled to the mud motor 3520 by a releasablecoupling 3600 in order to optimally provide for removal of the mud motor3530 and drill nit 3535 upon the completion of a drilling and casingoperation.

In a preferred embodiment, the shoe 3520 includes a releasable latchmechanism 3600 for retrieving and removing the mud motor 3530 and drillbit 3535 upon the completion of the drilling and casing formationoperations. In a preferred embodiment, the shoe 3520 further includes ananti-rotation device for maintaining the shoe 3520 in a substantiallystationary rotational position during operation of the apparatus 3600.In a preferred embodiment, the releasable latch mechanism 3600 isreleasably coupled to the shoe 3520.

The tubular member 3525 is supported by and coupled to the mandrel 3510.The tubular member 3525 is expanded in the radial direction and extrudedoff of the mandrel 3510. The tubular member 3525 may be fabricated fromany number of conventional commercially available materials such as, forexample, Oilfield Country Tubular Goods (OCTG), 13 chromium steeltubing/casing, automotive grade steel, or plastic tubing/casing. In apreferred embodiment, the tubular member 3525 is fabricated from OCTG inorder to maximize strength after expansion. The inner and outerdiameters of the tubular member 3525 may range, for example, fromapproximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. Ina preferred embodiment, the inner and outer diameters of the tubularmember 3525 range from about 3 to 15.5 inches and 3.5 to 16 inches,respectively in order to optimally provide minimal telescoping effect inthe most commonly drilled wellbore sizes. The tubular member 3525preferably comprises an annular member with solid walls.

In a preferred embodiment, the upper end portion 3580 of the tubularmember 3525 is slotted, perforated, or otherwise modified to catch orslow down the mandrel 3510 when the mandrel 3510 completes the extrusionof tubular member 3525. For typical tubular member 3525 materials, thelength of the tubular member 3525 is preferably limited to between about40 to 20,000 feet in length. The tubular member 3525 may comprise asingle tubular member or, alternatively, a plurality of tubular memberscoupled to one another.

The mud motor 3530 is coupled to the shoe 3520 and the drill bit 3535.The mud motor 3530 is also fluidicly coupled to the fluid passage 3555.In a preferred embodiment, the mud motor 3530 is driven by fluidicmaterials such as, for example, drilling mud, water, cement, epoxy,lubricants or slag mix conveyed from the fluid passage 3555 to the mudmotor 3530. In this manner, the mud motor 3530 drives the drill bit3535. The operating pressures and flow rates for operating mud motor3530 may range, for example, from about 0 to 12,000 psi and 0 to 10,000gallons/minute. In a preferred embodiment, the operating pressures andflow rates for operating mud motor 3530 range from about 0 to 5,000 psiand 40 to 3,000 gallons/minute.

The mud motor 3530 may comprise any number of conventional commerciallyavailable mud motors, modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the size of the mud motor3520 and drill bit 3535 are selected to pass through the interior of theshoe 3520 and the expanded tubular member 3525. In this manner, the mudmotor 3520 and drill bit 3535 may be retrieved from the downholelocation upon the conclusion of the drilling and casing operations.

The drill bit 3535 is coupled to the mud motor 3530. The drill bit 3535is preferably adapted to be powered by the mud motor 3530. In thismanner, the drill bit 3535 drills out new sections of the wellbore 3575.

The drill bit 3535 may comprise any number of conventional commerciallyavailable drill bits, modified in accordance with the teachings of thepresent disclosure. In a preferred embodiment, the size of the mud motor3520 and drill bit 3535 are selected to pass through the interior of theshoe 3520 and the expanded tubular member 3525. In this manner, the mudmotor 3520 and drill bit 3535 may be retrieved from the downholelocation upon the conclusion of the drilling and casing operations. Inseveral alternative preferred embodiments, the drill bit 3535 comprisesan eccentric drill bit, a bi-centered drill bit, or a small diameterdrill bit with an hydraulically actuated under reamer.

The first fluid passage 3540 permits fluidic materials to be transportedto the second fluid passage 3545, the pressure chamber 3550, the thirdfluid passage 3555, and the mud motor 3530. The first fluid passage 3540is coupled to and positioned within the support member 3505. The firstfluid passage 3540 preferably extends from a position adjacent to thesurface to the second fluid passage 3545 within the mandrel 3510. Thefirst fluid passage 3540 is preferably positioned along a centerline ofthe apparatus 3500.

The second fluid passage 3545 permits fluidic materials to be conveyedfrom the first fluid passage 3540 to the pressure chamber 3550, thethird fluid passage 3555, and the mud motor 3530. The second fluidpassage 3545 is coupled to and positioned within the mandrel 3510. Thesecond fluid passage 3545 preferably extends from a position adjacent tothe first fluid passage 3540 to the bottom of the mandrel 3510. Thesecond fluid passage 3545 is preferably positioned substantially alongthe centerline of the apparatus 3500.

The pressure chamber 3550 permits fluidic materials to be conveyed fromthe second fluid passage 3545 to the third fluid passage 3555, and themud motor 3530. The pressure chamber is preferably defined by the regionbelow the mandrel 3510 and within the tubular member 3525, mandrellauncher 3515, shoe 3520, and releasable coupling 3600. During operationof the apparatus 3500, pressurization of the pressure chamber 3550preferably causes the tubular member 3525 to be extruded off of themandrel 3510.

The third fluid passage 3555 permits fluidic materials to be conveyedfrom the pressure chamber 3550 to the mud motor 3530. The third fluidpassage 3555 may be coupled to and positioned within the shoe 3520 orreleasable coupling 3600. The third fluid passage 3555 preferablyextends from a position adjacent to the pressure chamber 3550 to thebottom of the shoe 3520 or releasable coupling 3600. The third fluidpassage 3555 is preferably positioned substantially along the centerlineof the apparatus 3500.

The fluid passages 3540, 3545, and 3555 are preferably selected toconvey materials such as cement, drilling mud or epoxies at flow ratesand pressures ranging from about 0 to 3,000 gallons/minute and 0 to9,000 psi in order to optimally operational efficiency.

The cup seal 3560 is coupled to and supported by the outer surface ofthe support member 3505. The cup seal 3560 prevents foreign materialsfrom entering the interior region of the tubular member 3525. The cupseal 3560 may comprise any number of conventional commercially availablecup seals such as, for example, TP cups or SIP cups modified inaccordance with the teachings of the present disclosure. In a preferredembodiment, the cup seal 3560 comprises a SIP cup, available fromHalliburton Energy Services in Dallas, Tex. in order to optimally blockthe entry of foreign materials and contain a body of lubricant. In apreferred embodiment, the apparatus 3500 includes a plurality of suchcup seals in order to optimally prevent the entry of foreign materialinto the interior region of the tubular member 3525 in the vicinity ofthe mandrel 3510.

In a preferred embodiment, a quantity of lubricant 3565 is provided inthe annular region above the mandrel 3510 within the interior of thetubular member 3525. In this manner, the extrusion of the tubular member3525 off of the mandrel 3510 is facilitated. The lubricant 3565 maycomprise any number of conventional commercially available lubricantssuch as, for example, Lubriplate, chlorine based lubricants, oil basedlubricants or Climax 1500 Antisieze (3100). In a preferred embodiment,the lubricant 3565 comprises Climax 1500 Antisieze (3100) available fromClimax Lubricants and Equipment Co. in Houston, Tex. in order tooptimally provide optimum lubrication to faciliate the expansionprocess.

The seals 3570 are coupled to and supported by the end portion 3580 ofthe tubular member 3525. The seals 3570 are further positioned on anouter surface of the end portion 3580 of the tubular member 3525. Theseals 3570 permit the overlapping joint between the lower end portion3585 of a preexisting section of casing 3590 and the end portion 3580 ofthe tubular member 3525 to be fluidicly sealed. The seals 3570 maycomprise any number of conventional commercially available seals suchas, for example, lead, rubber, Teflon, or epoxy seals modified inaccordance with the teachings of the present disclosure. In a preferredembodiment, the seals 3570 are molded from Stratalock epoxy availablefrom Halliburton Energy Services in Dallas, Tex. in order to optimallyprovide a load bearing interference fit between the end 3580 of thetubular member 3525 and the end 3585 of the pre-existing casing 3590.

In a preferred embodiment, the seals 3570 are selected to optimallyprovide a sufficient frictional force to support the expanded tubularmember 3525 from the pre-existing casing 3590. In a preferredembodiment, the frictional force optimally provided by the seals 3670ranges from about 1,000 to 1,000,000 lbf in order to optimally supportthe expanded tubular member 3525.

The releasable coupling 3600 is preferably releasably coupled to thebottom of the shoe 3520. In a preferred embodiment, the releasablecoupling 3600 includes fluidic seals for sealing the interface betweenthe releasable coupling 3600 and the shoe 3520. In this manner, thepressure chamber 3550 may be pressurized. The releasable coupling 3600may comprise any number of conventional commercially availablereleasable couplings suitable for drilling operations modified inaccordance with the teachings of the present disclosure.

As illustrated in FIG. 22A, during operation of the apparatus 3500, theapparatus 3500 is preferably initially positioned within a preexistingsection of a wellbore 3575 including a preexisting section of wellborecasing 3590. In a preferred embodiment, the upper end portion 3580 ofthe tubular member 3525 is positioned in an overlapping relationshipwith the lower end 3585 of the preexisting section of casing 3590. In apreferred embodiment, the apparatus 3500 is initially positioned in thewellbore 3575 with the drill bit 353 in contact with the bottom of thewellbore 3575. During the initial placement of the apparatus 3500 in thewellbore 3575, the tubular member 3525 is preferably supported by themandrel 3510.

As illustrated in FIG. 22B, a fluidic material 3595 is then pumped intothe first fluid passage 3540. The fluidic material 3595 is preferablyconveyed from the first fluid passage 3540 to the second fluid passage3545, the pressure chamber 3550, the third fluid passage 3555 and theinlet to the mud motor 3530. The fluidic material 3595 may comprise anynumber of conventional commercially available fluidic materials such as,for example, drilling mud, water, cement, epoxy or slag mix. The fluidicmaterial 3595 may be pumped into the first fluid passage 3540 atoperating pressures and flow rates ranging, for example, from about 0 to9,000 psi and 0 to 3,000 gallons/minute.

The fluidic material 3595 will enter the inlet for the mud motor 3530and drive the mud motor 3530. The fluidic material 3595 will then exitthe mud motor 3530 and enter the annular region surrounding theapparatus 3500 within the wellbore 3575. The mud motor 3530 will in turndrive the drill bit 3535. The operation of the drill bit 3535 will drillout a new section of the wellbore 3575.

In the case where the fluidic material 3595 comprises a hardenablefluidic material, the fluidic material 3595 preferably is permitted tocure and form an outer annular body surrounding the periphery of theexpanded tubular member 3525. Alternatively, in the case where thefluidic material 3595 is a non-hardenable fluidic material, the tubularmember 3595 preferably is expanded into intimate contact with theinterior walls of the wellbore 3575. In this manner, an outer annularbody is not provided in all applications.

As illustrated in FIG. 22C, at some point during operation of the mudmotor 3530 and drill bit 3535, the pressure drop across the mud motor3530 will create sufficient back pressure to cause the operatingpressure within the pressure chamber 3550 to elevate to the pressurenecessary to extrude the tubular member 3525 off of the mandrel 3510.The elevation of the operating pressure within the pressure chamber 3550will then cause the tubular member 3525 to extrude off of the mandrel3510 as illustrated in FIG. 22D. For typical tubular members 3525, thenecessary operating pressure may range, for example, from about 1,000 to9,000 psi. In this manner, a wellbore casing is formed simultaneous withthe drilling out of a new section of wellbore.

In a particularly preferred embodiment, during the operation of theapparatus 3500, the apparatus 3500 is lowered into the wellbore 3575until the drill bit 3535 is proximate the bottom of the wellbore 3575.Throughout this process, the tubular member 3525 is preferably supportedby the mandrel 3510. The apparatus 3500 is then lowered until the drillbit 3535 is placed in contact with the bottom of the wellbore 3575. Atthis point, at least a portion of the weight of the tubular member 3525is supported by the drill bit 3535.

The fluidic material 3595 is then pumped into the first fluid passage3540, second fluid passage 3545, pressure chamber 3550, third fluidpassage 3555, and the inlet of the mud motor 3530. The mud motor 3530then drives the drill bit 3535 to drill out a new section of thewellbore 3575. Once the differential pressure across the mud motor 3530exceeds the minimum extrusion pressure for the tubular member 3525, thetubular member 3525 begins to extrude off of the mandrel 3510. As thetubular member 3525 is extruded off of the mandrel 3510, the weight ofthe extruded portion of the tubular member 3525 is transferred to andsupported by the drill bit 3535. In a preferred embodiment, the pumpingpressure of the fluidic material 3595 is maintained substantiallyconstant throughout this process. At some point during the process ofextruding the tubular member 3525 off of the mandrel 3510, a sufficientportion of the weight of the tubular member 3525 is transferred to thedrill bit 3535 to stop the extrusion process due to the opposing force.Continued drilling by the drill bit 3535 eventually transfers asufficient portion of the weight of the extruded portion of the tubularmember 3525 back to the mandrel 3510. At this point, the extrusion ofthe tubular member 3525 off of the mandrel 3510 continues. In thismanner, the support member 3505 never has to be moved and no drillpipeconnections have to be made at the surface since the new section of thewellbore casing within the newly drilled section of wellbore is createdby the constant downward feeding of the expanded tubular member 3525 offof the mandrel 3510.

Once the new section of wellbore that is lined with the fully expandedtubular member 3525 is completed, the support member 3505 and mandrel3510 are removed from the wellbore 3575. The drilling assembly includingthe mud motor 3530 and drill bit 3535 are then preferably removed bylowering a drillstring into the new section of wellbore casing andretrieving the drilling assembly by using the latch 3600. The expandedtubular member 3525 is then cemented using conventional squeezecementing methods to provide a solid annular sealing member around theperiphery of the expanded tubular member 3525.

Alternatively, the apparatus 3500 may be used to repair or form anunderground pipeline or form a support member for a structure. Inseveral preferred alternative embodiments, the teachings of theapparatus 3500 are combined with the teachings of the embodimentsillustrated in FIGS. 1-21. For example, by operably coupling the mudmotor 3530 and drill bit 3535 to the pressure chambers used to cause theradial expansion of the tubular members of the embodiments illustratedand described with reference to FIGS. 1-21, the use of plugs may beeliminated and radial expansion of tubular members can be combined withthe drilling out of new sections of wellbore.

A method of creating a casing in a borehole located in a subterraneanformation has been described that includes installing a tubular linerand a mandrel in the borehole. A body of fluidic material is theninjected into the borehole. The tubular liner is then radially expandedby extruding the liner off of the mandrel. The injecting preferablyincludes injecting a hardenable fluidic sealing material into an annularregion located between the borehole and the exterior of the tubularliner; and a non hardenable fluidic material into an interior region ofthe tubular liner below the mandrel. The method preferably includesfluidicly isolating the annular region from the interior region beforeinjecting the second quantity of the non hardenable sealing materialinto the interior region. The injecting the hardenable fluidic sealingmaterial is preferably provided at operating pressures and flow ratesranging from about 0 to 5000 psi and 0 to 1,500 gallons/min. Theinjecting of the non hardenable fluidic material is preferably providedat operating pressures and flow rates ranging from about 500 to 9000 psiand 40 to 3,000 gallons/min. The injecting of the non hardenable fluidicmaterial is preferably provided at reduced operating pressures and flowrates during an end portion of the extruding. The non hardenable fluidicmaterial is preferably injected below the mandrel. The method preferablyincludes pressurizing a region of the tubular liner below the mandrel.The region of the tubular liner below the mandrel is preferablypressurized to pressures ranging from about 500 to 9,000 psi. The methodpreferably includes fluidicly isolating an interior region of thetubular liner from an exterior region of the tubular liner. The methodfurther preferably includes curing the hardenable sealing material, andremoving at least a portion of the cured sealing material located withinthe tubular liner. The method further preferably includes overlappingthe tubular liner with an existing wellbore casing. The method furtherpreferably includes sealing the overlap between the tubular liner andthe existing wellbore casing. The method further preferably includessupporting the extruded tubular liner using the overlap with theexisting wellbore casing. The method further preferably includes testingthe integrity of the seal in the overlap between the tubular liner andthe existing wellbore casing. The method further preferably includesremoving at least a portion of the hardenable fluidic sealing materialwithin the tubular liner before curing. The method further preferablyincludes lubricating the surface of the mandrel. The method furtherpreferably includes absorbing shock. The method further preferablyincludes catching the mandrel upon the completion of the extruding.

An apparatus for creating a casing in a borehole located in asubterranean formation has been described that includes a supportmember, a mandrel, a tubular member, and a shoe. The support memberincludes a first fluid passage. The mandrel is coupled to the supportmember and includes a second fluid passage. The tubular member iscoupled to the mandrel. The shoe is coupled to the tubular liner andincludes a third fluid passage. The first, second and third fluidpassages are operably coupled. The support member preferably furtherincludes a pressure relief passage, and a flow control valve coupled tothe first fluid passage and the pressure relief passage. The supportmember further preferably includes a shock absorber. The support memberpreferably includes one or more sealing members adapted to preventforeign material from entering an interior region of the tubular member.The mandrel is preferably expandable. The tubular member is preferablyfabricated from materials selected from the group consisting of OilfieldCountry Tubular Goods, 13 chromium steel tubing/casing, and plasticcasing. The tubular member preferably has inner and outer diametersranging from about 3 to 15.5 inches and 3.5 to 16 inches, respectively.The tubular member preferably has a plastic yield point ranging fromabout 40,000 to 135,000 psi. The tubular member preferably includes oneor more sealing members at an end portion. The tubular member preferablyincludes one or more pressure relief holes at an end portion. Thetubular member preferably includes a catching member at an end portionfor slowing down the mandrel. The shoe preferably includes an inlet portcoupled to the third fluid passage, the inlet port adapted to receive aplug for blocking the inlet port. The shoe preferably is drillable.

A method of joining a second tubular member to a first tubular member,the first tubular member having an inner diameter greater than an outerdiameter of the second tubular member, has been described that includespositioning a mandrel within an interior region of the second tubularmember, positioning the first and second tubular members in anoverlapping relationship, pressurizing a portion of the interior regionof the second tubular member; and extruding the second tubular memberoff of the mandrel into engagement with the first tubular member. Thepressurizing of the portion of the interior region of the second tubularmember is preferably provided at operating pressures ranging from about500 to 9,000 psi. The pressurizing of the portion of the interior regionof the second tubular member is preferably provided at reduced operatingpressures during a latter portion of the extruding. The method furtherpreferably includes sealing the overlap between the first and secondtubular members. The method further preferably includes supporting theextruded first tubular member using the overlap with the second tubularmember. The method further preferably includes lubricating the surfaceof the mandrel. The method further preferably includes absorbing shock.

A liner for use in creating a new section of wellbore casing in asubterranean formation adjacent to an already existing section ofwellbore casing has been described that includes an annular member. Theannular member includes one or more sealing members at an end portion ofthe annular member, and one or more pressure relief passages at an endportion of the annular member.

A wellbore casing has been described that includes a tubular liner andan annular body of a cured fluidic sealing material. The tubular lineris formed by the process of extruding the tubular liner off of amandrel. The tubular liner is preferably formed by the process ofplacing the tubular liner and mandrel within the wellbore, andpressurizing an interior portion of the tubular liner. The annular bodyof the cured fluidic sealing material is preferably formed by theprocess of injecting a body of hardenable fluidic sealing material intoan annular region external of the tubular liner. During thepressurizing, the interior portion of the tubular liner is preferablyfluidicly isolated from an exterior portion of the tubular liner. Theinterior portion of the tubular liner is preferably pressurized topressures ranging from about 500 to 9,000 psi. The tubular linerpreferably overlaps with an existing wellbore casing. The wellborecasing preferably further includes a seal positioned in the overlapbetween the tubular liner and the existing wellbore casing. Tubularliner is preferably supported the overlap with the existing wellborecasing.

A method of repairing an existing section of a wellbore casing within aborehole has been described that includes installing a tubular liner anda mandrel within the wellbore casing, injecting a body of a fluidicmaterial into the borehole, pressurizing a portion of an interior regionof the tubular liner, and radially expanding the liner in the boreholeby extruding the liner off of the mandrel. In a preferred embodiment,the fluidic material is selected from the group consisting of slag mix,cement, drilling mud, and epoxy. In a preferred embodiment, the methodfurther includes fluidicly isolating an interior region of the tubularliner from an exterior region of the tubular liner. In a preferredembodiment, the injecting of the body of fluidic material is provided atoperating pressures and flow rates ranging from about 500 to 9,000 psiand 40 to 3,000 gallons/min. In a preferred embodiment, the injecting ofthe body of fluidic material is provided at reduced operating pressuresand flow rates during an end portion of the extruding. In a preferredembodiment, the fluidic material is injected below the mandrel. In apreferred embodiment, a region of the tubular liner below the mandrel ispressurized. In a preferred embodiment, the region of the tubular linerbelow the mandrel is pressurized to pressures ranging from about 500 to9,000 psi. In a preferred embodiment, the method further includesoverlapping the tubular liner with the existing wellbore casing. In apreferred embodiment, the method further includes sealing the interfacebetween the tubular liner and the existing wellbore casing. In apreferred embodiment, the method further includes supporting theextruded tubular liner using the existing wellbore casing. In apreferred embodiment, the method further includes testing the integrityof the seal in the interface between the tubular liner and the existingwellbore casing. In a preferred embodiment, method further includeslubricating the surface of the mandrel. In a preferred embodiment, themethod further includes absorbing shock. In a preferred embodiment, themethod further includes catching the mandrel upon the completion of theextruding. In a preferred embodiment, the method further includesexpanding the mandrel in a radial direction.

A tie-back liner for lining an existing wellbore casing has beendescribed that includes a tubular liner and an annular body of a curedfluidic sealing material. The tubular liner is formed by the process ofextruding the tubular liner off of a mandrel. The annular body of acured fluidic sealing material is coupled to the tubular liner. In apreferred embodiment, the tubular liner is formed by the process ofplacing the tubular liner and mandrel within the wellbore, andpressurizing an interior portion of the tubular liner. In a preferredembodiment, during the pressurizing, the interior portion of the tubularliner is fluidicly isolated from an exterior portion of the tubularliner. In a preferred embodiment, the interior portion of the tubularliner is pressurized at pressures ranging from about 500 to 9,000 psi.In a preferred embodiment, the annular body of a cured fluidic sealingmaterial is formed by the process of injecting a body of hardenablefluidic sealing material into an annular region between the existingwellbore casing and the tubular liner. In a preferred embodiment, thetubular liner overlaps with another existing wellbore casing. In apreferred embodiment, the tie-back liner further includes a sealpositioned in the overlap between the tubular liner and the otherexisting wellbore casing. In a preferred embodiment, tubular liner issupported by the overlap with the other existing wellbore casing.

An apparatus for expanding a tubular member has been described thatincludes a support member, a mandrel, a tubular member, and a shoe. Thesupport member includes a first fluid passage. The mandrel is coupled tothe support member. The mandrel includes a second fluid passage operablycoupled to the first fluid passage, an interior portion, and an exteriorportion. The interior portion of the mandrel is drillable. The tubularmember is coupled to the mandrel. The shoe is coupled to the tubularmember. The shoe includes a third fluid passage operably coupled to thesecond fluid passage, an interior portion, and an exterior portion. Theinterior portion of the shoe is drillable. Preferably, the interiorportion of the mandrel includes a tubular member and a load bearingmember. Preferably, the load bearing member comprises a drillable body.Preferably, the interior portion of the shoe includes a tubular member,and a load bearing member. Preferably, the load bearing member comprisesa drillable body. Preferably, the exterior portion of the mandrelcomprises an expansion cone. Preferably, the expansion cone isfabricated from materials selected from the group consisting of toolsteel, titanium, and ceramic. Preferably, the expansion cone has asurface hardness ranging from about 58 to 62 Rockwell C. Preferably atleast a portion of the apparatus is drillable.

A wellhead has also been described that includes an outer casing and aplurality of substantially concentric and overlapping inner casingscoupled to the outer casing. Each inner casing is supported by contactpressure between an outer surface of the inner casing and an innersurface of the outer casing. In a preferred embodiment, the outer casinghas a yield strength ranging from about 40,000 to 135,000 psi. In apreferred embodiment, the outer casing has a burst strength ranging fromabout 5,000 to 20,000 psi. In a preferred embodiment, the contactpressure between the inner casings and the outer casing ranges fromabout 500 to 10,000 psi. In a preferred embodiment, one or more of theinner casings include one or more sealing members that contact with aninner surface of the outer casing. In a preferred embodiment, thesealing members are selected from the group consisting of lead, rubber,Teflon, epoxy, and plastic. In a preferred embodiment, a Christmas treeis coupled to the outer casing. In a preferred embodiment, a drillingspool is coupled to the outer casing. In a preferred embodiment, atleast one of the inner casings is a production casing.

A wellhead has also been described that includes an outer casing atleast partially positioned within a wellbore and a plurality ofsubstantially concentric inner casings coupled to the interior surfaceof the outer casing by the process of expanding one or more of the innercasings into contact with at least a portion of the interior surface ofthe outer casing. In a preferred embodiment, the inner casings areexpanded by extruding the inner casings off of a mandrel. In a preferredembodiment, the inner casings are expanded by the process of placing theinner casing and a mandrel within the wellbore; and pressurizing aninterior portion of the inner casing. In a preferred embodiment, duringthe pressurizing, the interior portion of the inner casing is fluidiclyisolated from an exterior portion of the inner casing. In a preferredembodiment, the interior portion of the inner casing is pressurized atpressures ranging from about 500 to 9,000 psi. In a preferredembodiment, one or more seals are positioned in the interface betweenthe inner casings and the outer casing. In a preferred embodiment, theinner casings are supported by their contact with the outer casing.

A method of forming a wellhead has also been described that includesdrilling a wellbore. An outer casing is positioned at least partiallywithin an upper portion of the wellbore. A first tubular member ispositioned within the outer casing. At least a portion of the firsttubular member is expanded into contact with an interior surface of theouter casing. A second tubular member is positioned within the outercasing and the first tubular member. At least a portion of the secondtubular member is expanded into contact with an interior portion of theouter casing. In a preferred embodiment, at least a portion of theinterior of the first tubular member is pressurized. In a preferredembodiment, at least a portion of the interior of the second tubularmember is pressurized. In a preferred embodiment, at least a portion ofthe interiors of the first and second tubular members are pressurized.In a preferred embodiment, the pressurizing of the portion of theinterior region of the first tubular member is provided at operatingpressures ranging from about 500 to 9,000 psi. In a preferredembodiment, the pressurizing of the portion of the interior region ofthe second tubular member is provided at operating pressures rangingfrom about 500 to 9,000 psi. In a preferred embodiment, the pressurizingof the portion of the interior region of the first and second tubularmembers is provided at operating pressures ranging from about 500 to9,000 psi. In a preferred embodiment, the pressurizing of the portion ofthe interior region of the first tubular member is provided at reducedoperating pressures during a latter portion of the expansion. In apreferred embodiment, the pressurizing of the portion of the interiorregion of the second tubular member is provided at reduced operatingpressures during a latter portion of the expansion. In a preferredembodiment, the pressurizing of the portion of the interior region ofthe first and second tubular members is provided at reduced operatingpressures during a latter portion of the expansions. In a preferredembodiment, the contact between the first tubular member and the outercasing is sealed. In a preferred embodiment, the contact between thesecond tubular member and the outer casing is sealed. In a preferredembodiment, the contact between the first and second tubular members andthe outer casing is sealed. In a preferred embodiment, the expandedfirst tubular member is supported using the contact with the outercasing. In a preferred embodiment, the expanded second tubular member issupported using the contact with the outer casing. In a preferredembodiment, the expanded first and second tubular members are supportedusing their contacts with the outer casing. In a preferred embodiment,the first and second tubular members are extruded off of a mandrel. In apreferred embodiment, the surface of the mandrel is lubricated. In apreferred embodiment, shock is absorbed. In a preferred embodiment, themandrel is expanded in a radial direction. In a preferred embodiment,the first and second tubular members are positioned in an overlappingrelationship. In a preferred embodiment, an interior region of the firsttubular member is fluidicly isolated from an exterior region of thefirst tubular member. In a preferred embodiment, an interior region ofthe second tubular member is fluidicly isolated from an exterior regionof the second tubular member. In a preferred embodiment, the interiorregion of the first tubular member is fluidicly isolated from the regionexterior to the first tubular member by injecting one or more plugs intothe interior of the first tubular member. In a preferred embodiment, theinterior region of the second tubular member is fluidicly isolated fromthe region exterior to the second tubular member by injecting one ormore plugs into the interior of the second tubular member. In apreferred embodiment, the pressurizing of the portion of the interiorregion of the first tubular member is provided by injecting a fluidicmaterial at operating pressures and flow rates ranging from about 500 to9,000 psi and 40 to 3,000 gallons/minute. In a preferred embodiment, thepressurizing of the portion of the interior region of the second tubularmember is provided by injecting a fluidic material at operatingpressures and flow rates ranging from about 500 to 9,000 psi and 40 to3,000 gallons/minute. In a preferred embodiment, fluidic material isinjected beyond the mandrel. In a preferred embodiment, a region of thetubular members beyond the mandrel is pressurized. In a preferredembodiment, the region of the tubular members beyond the mandrel ispressurized to pressures ranging from about 500 to 9,000 psi. In apreferred embodiment, the first tubular member comprises a productioncasing. In a preferred embodiment, the contact between the first tubularmember and the outer casing is sealed. In a preferred embodiment, thecontact between the second tubular member and the outer casing issealed. In a preferred embodiment, the expanded first tubular member issupported using the outer casing. In a preferred embodiment, theexpanded second tubular member is supported using the outer casing. In apreferred embodiment, the integrity of the seal in the contact betweenthe first tubular member and the outer casing is tested. In a preferredembodiment, the integrity of the seal in the contact between the secondtubular member and the outer casing is tested. In a preferredembodiment, the mandrel is caught upon the completion of the extruding.In a preferred embodiment, the mandrel is drilled out. In a preferredembodiment, the mandrel is supported with coiled tubing. In a preferredembodiment, the mandrel is coupled to a drillable shoe.

An apparatus has also been described that includes an outer tubularmember, and a plurality of substantially concentric and overlappinginner tubular members coupled to the outer tubular member. Each innertubular member is supported by contact pressure between an outer surfaceof the inner casing and an inner surface of the outer inner tubularmember. In a preferred embodiment, the outer tubular member has a yieldstrength ranging from about 40,000 to 135,000 psi. In a preferredembodiment, the outer tubular member has a burst strength ranging fromabout 5,000 to 20,000 psi. In a preferred embodiment, the contactpressure between the inner tubular members and the outer tubular memberranges from about 500 to 10,000 psi. In a preferred embodiment, one ormore of the inner tubular members include one or more sealing membersthat contact with an inner surface of the outer tubular member. In apreferred embodiment, the sealing members are selected from the groupconsisting of rubber, lead, plastic, and epoxy.

An apparatus has also been described that includes an outer tubularmember, and a plurality of substantially concentric inner tubularmembers coupled to the interior surface of the outer tubular member bythe process of expanding one or more of the inner tubular members intocontact with at least a portion of the interior surface of the outertubular member. In a preferred embodiment, the inner tubular members areexpanded by extruding the inner tubular members off of a mandrel. In apreferred embodiment, the inner tubular members are expanded by theprocess of: placing the inner tubular members and a mandrel within theouter tubular member; and pressurizing an interior portion of the innercasing. In a preferred embodiment, during the pressurizing, the interiorportion of the inner tubular member is fluidicly isolated from anexterior portion of the inner tubular member. In a preferred embodiment,the interior portion of the inner tubular member is pressurized atpressures ranging from about 500 to 9,000 psi. In a preferredembodiment, the apparatus further includes one or more seals positionedin the interface between the inner tubular members and the outer tubularmember. In a preferred embodiment, the inner tubular members aresupported by their contact with the outer tubular member.

A wellbore casing has also been described that includes a first tubularmember, and a second tubular member coupled to the first tubular memberin an overlapping relationship. The inner diameter of the first tubularmember is substantially equal to the inner diameter of the secondtubular member. In a preferred embodiment, the first tubular memberincludes a first thin wall section, wherein the second tubular memberincludes a second thin wall section, and wherein the first thin wallsection is coupled to the second thin wall section. In a preferredembodiment, first and second thin wall sections are deformed. In apreferred embodiment, the first tubular member includes a firstcompressible member coupled to the first thin wall section, and whereinthe second tubular member includes a second compressible member coupledto the second thin wall section. In a preferred embodiment, the firstthin wall section and the first compressible member are coupled to thesecond thin wall section and the second compressible member. In apreferred embodiment, the first and second thin wall sections and thefirst and second compressible members are deformed.

A wellbore casing has also been described that includes a tubular memberincluding at least one thin wall section and a thick wall section, and acompressible annular member coupled to each thin wall section. In apreferred embodiment, the compressible annular member is fabricated frommaterials selected from the group consisting of rubber, plastic, metaland epoxy. In a preferred embodiment, the wall thickness of the thinwall section ranges from about 50 to 100% of the wall thickness of thethick wall section. In a preferred embodiment, the length of the thinwall section ranges from about 120 to 2400 inches. In a preferredembodiment, the compressible annular member is positioned along the thinwall section. In a preferred embodiment, the compressible annular memberis positioned along the thin and thick wall sections. In a preferredembodiment, the tubular member is fabricated from materials selectedfrom the group consisting of oilfield country tubular goods, stainlesssteel, low alloy steel, carbon steel, automotive grade steel, plastics,fiberglass, high strength and/or deformable materials. In a preferredembodiment, the wellbore casing includes a first thin wall at a firstend of the casing, and a second thin wall at a second end of the casing.

A method of creating a casing in a borehole located in a subterraneanformation has also been described that includes supporting a tubularliner and a mandrel in the borehole using a support member, injectingfluidic material into the borehole, pressurizing an interior region ofthe mandrel, displacing a portion of the mandrel relative to the supportmember, and radially expanding the tubular liner. In a preferredembodiment, the injecting includes injecting hardenable fluidic sealingmaterial into an annular region located between the borehole and theexterior of the tubular liner, and injecting non hardenable fluidicmaterial into an interior region of the mandrel. In a preferredembodiment, the method further includes fluidicly isolating the annularregion from the interior region before injecting the non hardenablefluidic material into the interior region of the mandrel. In a preferredembodiment, the injecting of the hardenable fluidic sealing material isprovided at operating pressures and flow rates ranging from about 0 to5,000 psi and 0 to 1,500 gallons/min. In a preferred embodiment, theinjecting of the non hardenable fluidic material is provided atoperating pressures and flow rates ranging from about 500 to 9,000 psiand 40 to 3,000 gallons/min. In a preferred embodiment, the injecting ofthe non hardenable fluidic material is provided at reduced operatingpressures and flow rates during an end portion of the radial expansion.In a preferred embodiment, the fluidic material is injected into one ormore pressure chambers. In a preferred embodiment, the one or morepressure chambers are pressurized. In a preferred embodiment, thepressure chambers are pressurized to pressures ranging from about 500 to9,000 psi. In a preferred embodiment, the method further includesfluidicly isolating an interior region of the mandrel from an exteriorregion of the mandrel. In a preferred embodiment, the interior region ofthe mandrel is isolated from the region exterior to the mandrel byinserting one or more plugs into the injected fluidic material. In apreferred embodiment, the method further includes curing at least aportion of the fluidic material, and removing at least a portion of thecured fluidic material located within the tubular liner. In a preferredembodiment, the method further includes overlapping the tubular linerwith an existing wellbore casing. In a preferred embodiment, the methodfurther includes sealing the overlap between the tubular liner and theexisting wellbore casing. In a preferred embodiment, the method furtherincludes supporting the extruded tubular liner using the overlap withthe existing wellbore casing. In a preferred embodiment, the methodfurther includes testing the integrity of the seal in the overlapbetween the tubular liner and the existing wellbore casing. In apreferred embodiment, the method further includes removing at least aportion of the hardenable fluidic sealing material within the tubularliner before curing. In a preferred embodiment, the method furtherincludes lubricating the surface of the mandrel. In a preferredembodiment, the method further includes absorbing shock. In a preferredembodiment, the method further includes catching the mandrel upon thecompletion of the extruding. In a preferred embodiment, the methodfurther includes drilling out the mandrel. In a preferred embodiment,the method further includes supporting the mandrel with coiled tubing.In a preferred embodiment, the mandrel reciprocates. In a preferredembodiment, the mandrel is displaced in a first direction during thepressurization of the interior region of the mandrel, and the mandrel isdisplaced in a second direction during a de-pressurization of theinterior region of the mandrel. In a preferred embodiment, the tubularliner is maintained in a substantially stationary position during thepressurization of the interior region of the mandrel. In a preferredembodiment, the tubular liner is supported by the mandrel during ade-pressurization of the interior region of the mandrel.

A wellbore casing has also been described that includes a first tubularmember having a first inside diameter, and a second tubular memberhaving a second inside diameter substantially equal to the first insidediameter coupled to the first tubular member in an overlappingrelationship. The first and second tubular members are coupled by theprocess of deforming a portion of the second tubular member into contactwith a portion of the first tubular member. In a preferred embodiment,the second tubular member is deformed by the process of placing thefirst and second tubular members in an overlapping relation ship,radially expanding at least a portion of the first tubular member, andradially expanding the second tubular member. In a preferred embodiment,the second tubular member is radially expanded by the process ofsupporting the second tubular member and a mandrel within the wellboreusing a support member, injecting a fluidic material into the wellbore,pressurizing an interior region of the mandrel, and displacing a portionof the mandrel relative to the support member. In a preferredembodiment, the injecting includes injecting hardenable fluidic sealingmaterial into an annular region located between the borehole and theexterior of the second liner, and injecting non hardenable fluidicmaterial into an interior region of the mandrel. In a preferredembodiment, the wellbore casing further includes fluidicly isolating theannular region from the interior region of the mandrel before injectingthe non hardenable fluidic material into the interior region of themandrel. In a preferred embodiment, the injecting of the hardenablefluidic sealing material is provided at operating pressures and flowrates ranging from about 0 to 5,000 psi and 0 to 1,500 gallons/min. In apreferred embodiment, the injecting of the non hardenable fluidicmaterial is provided at operating pressures and flow rates ranging fromabout 500 to 9,000 psi and 40 to 3,000 gallons/min. In a preferredembodiment, the injecting of the non hardenable fluidic material isprovided at reduced operating pressures and flow rates during an endportion of the radial expansion. In a preferred embodiment, the fluidicmaterial is injected into one or more pressure chambers. In a preferredembodiment, one or more pressure chambers are pressurized. In apreferred embodiment, the pressure chambers are pressurized to pressuresranging from about 500 to 9,000 psi. In a preferred embodiment, thewellbore casing further includes fluidicly isolating an interior regionof the mandrel from an exterior region of the mandrel. In a preferredembodiment, the interior region of the mandrel is isolated from theregion exterior to the mandrel by inserting one or more plugs into theinjected fluidic material. In a preferred embodiment, the wellborecasing further includes curing at least a portion of the fluidicmaterial, and removing at least a portion of the cured fluidic materiallocated within the second tubular liner. In a preferred embodiment, thewellbore casing further includes sealing the overlap between the firstand second tubular liners. In a preferred embodiment, the wellborecasing further includes supporting the second tubular liner using theoverlap with the first tubular liner. In a preferred embodiment, thewellbore casing further includes testing the integrity of the seal inthe overlap between the first and second tubular liners. In a preferredembodiment, the wellbore casing further includes removing at least aportion of the hardenable fluidic sealing material within the secondtubular liner before curing. In a preferred embodiment, the wellborecasing further includes lubricating the surface of the mandrel. In apreferred embodiment, the wellbore casing further includes absorbingshock. In a preferred embodiment, the wellbore casing further includescatching the mandrel upon the completion of the radial expansion. In apreferred embodiment, the wellbore casing further includes drilling outthe mandrel. In a preferred embodiment, the wellbore casing furtherinclude supporting the mandrel with coiled tubing. In a preferredembodiment, the mandrel reciprocates. In a preferred embodiment, themandrel is displaced in a first direction during the pressurization ofthe interior region of the mandrel; and wherein the mandrel is displacedin a second direction during a de-pressurization of the interior regionof the mandrel. In a preferred embodiment, the second tubular liner ismaintained in a substantially stationary position during thepressurization of the interior region of the mandrel. In a preferredembodiment, the second tubular liner is supported by the mandrel duringa de-pressurization of the interior region of the mandrel.

An apparatus for expanding a tubular member has also been described thatincludes a support member including a fluid passage, a mandrel movablycoupled to the support member including an expansion cone, at least onepressure chamber defined by and positioned between the support memberand mandrel fluidicly coupled to the first fluid passage, and one ormore releasable supports coupled to the support member adapted tosupport the tubular member. In a preferred embodiment, the fluid passageincludes a throat passage having a reduced inner diameter. In apreferred embodiment, the mandrel includes one or more annular pistons.In a preferred embodiment, the apparatus includes a plurality ofpressure chambers. In a preferred embodiment, the pressure chambers areat least partially defined by annular pistons. In a preferredembodiment, the releasable supports are positioned below the mandrel. Ina preferred embodiment, the releasable supports are positioned above themandrel. In a preferred embodiment, the releasable supports comprisehydraulic slips. In a preferred embodiment, the releasable supportscomprise mechanical slips. In a preferred embodiment, the releasablesupports comprise drag blocks. In a preferred embodiment, the mandrelincludes one or more annular pistons, and an expansion cone coupled tothe annular pistons. In a preferred embodiment, one or more of theannular pistons include an expansion cone. In a preferred embodiment,the pressure chambers comprise annular pressure chambers.

An apparatus has also been described that includes one or more solidtubular members, each solid tubular member including one or moreexternal seals, one or more slotted tubular members coupled to the solidtubular members, and a shoe coupled to one of the slotted tubularmembers. In a preferred embodiment, the apparatus further includes oneor more intermediate solid tubular members coupled to and interleavedamong the slotted tubular members, each intermediate solid tubularmember including one or more external seals. In a preferred embodiment,the apparatus further includes one or more valve members. In a preferredembodiment, one or more of the intermediate solid tubular membersinclude one or more valve members.

A method of joining a second tubular member to a first tubular member,the first tubular member having an inner diameter greater than an outerdiameter of the second tubular member, has also been described thatincludes positioning a mandrel within an interior region of the secondtubular member, pressurizing a portion of the interior region of themandrel, displacing the mandrel relative to the second tubular member,and extruding at least a portion of the second tubular member off of themandrel into engagement with the first tubular member. In a preferredembodiment, the pressurizing of the portion of the interior region ofthe mandrel is provided at operating pressures ranging from about 500 to9,000 psi. In a preferred embodiment, the pressurizing of the portion ofthe interior region of the mandrel is provided at reduced operatingpressures during a latter portion of the extruding. In a preferredembodiment, the method further includes sealing the interface betweenthe first and second tubular members. In a preferred embodiment, themethod further includes supporting the extruded second tubular memberusing the interface with the first tubular member. In a preferredembodiment, the method further includes lubricating the surface of themandrel. In a preferred embodiment, the method further includesabsorbing shock. In a preferred embodiment, the method further includespositioning the first and second tubular members in an overlappingrelationship. In a preferred embodiment, the method further includesfluidicly isolating an interior region of the mandrel an exterior regionof the mandrel. In a preferred embodiment, the interior region of themandrel is fluidicly isolated from the region exterior to the mandrel byinjecting one or more plugs into the interior of the mandrel. In apreferred embodiment, the pressurizing of the portion of the interiorregion of the mandrel is provided by injecting a fluidic material atoperating pressures and flow rates ranging from about 500 to 9,000 psiand 40 to 3,000 gallons/minute. In a preferred embodiment, the methodfurther includes injecting fluidic material beyond the mandrel. In apreferred embodiment, one or more pressure chambers defined by themandrel are pressurized. In a preferred embodiment, the pressurechambers are pressurized to pressures ranging from about 500 to 9,000psi. In a preferred embodiment, the first tubular member comprises anexisting section of a wellbore. In a preferred embodiment, the methodfurther includes sealing the interface between the first and secondtubular members. In a preferred embodiment, the method further includessupporting the extruded second tubular member using the first tubularmember. In a preferred embodiment, the method further includes testingthe integrity of the seal in the interface between the first tubularmember and the second tubular member. In a preferred embodiment, themethod further includes catching the mandrel upon the completion of theextruding. In a preferred embodiment, the method further includesdrilling out the mandrel. In a preferred embodiment, the method furtherinclude supporting the mandrel with coiled tubing. In a preferredembodiment, the method further includes coupling the mandrel to adrillable shoe. In a preferred embodiment, the mandrel is displaced inthe longitudinal direction. In a preferred embodiment, the mandrel isdisplaced in a first direction during the pressurization and in a seconddirection during a de-pressurization.

An apparatus has also been described that includes one or more primarysolid tubulars, each primary solid tubular including one or moreexternal annular seals, n slotted tubulars coupled to the primary solidtubulars, n-1 intermediate solid tubulars coupled to and interleavedamong the slotted tubulars, each intermediate solid tubular includingone or more external annular seals, and a shoe coupled to one of theslotted tubulars.

A method of isolating a first subterranean zone from a secondsubterranean zone in a wellbore has also been described that includespositioning one or more primary solid tubulars within the wellbore, theprimary solid tubulars traversing the first subterranean zone,positioning one or more slotted tubulars within the wellbore, theslotted tubulars traversing the second subterranean zone, fluidiclycoupling the slotted tubulars and the solid tubulars, and preventing thepassage of fluids from the first subterranean zone to the secondsubterranean zone within the wellbore external to the solid and slottedtubulars.

A method of extracting materials from a producing subterranean zone in awellbore, at least a portion of the wellbore including a casing, hasalso been described that includes positioning one or more primary solidtubulars within the wellbore, fluidicly coupling the primary solidtubulars with the casing, positioning one or more slotted tubularswithin the wellbore, the slotted tubulars traversing the producingsubterranean zone, fluidicly coupling the slotted tubulars with thesolid tubulars, fluidicly isolating the producing subterranean zone fromat least one other subterranean zone within the wellbore, and fluidiclycoupling at least one of the slotted tubulars from the producingsubterranean zone. In a preferred embodiment, the method furtherincludes controllably fluidicly decoupling at least one of the slottedtubulars from at least one other of the slotted tubulars.

A method of creating a casing in a borehole while also drilling theborehole also has been described that includes installing a tubularliner, a mandrel, and a drilling assembly in the borehole. A fluidicmaterial is injected within the tubular liner, mandrel and drillingassembly. At least a portion of the tubular liner is radially expandedwhile the borehole is drilled using the drilling assembly. In apreferred embodiment, the injecting includes injecting the fluidicmaterial within an expandible chamber. In a preferred embodiment, theinjecting includes injecting hardenable fluidic sealing material into anannular region located between the borehole and the exterior of thetubular liner. In a preferred embodiment, the injecting of thehardenable fluidic sealing material is provided at operating pressuresand flow rates ranging from about 0 to 5,000 psi and 0 to 1,500gallons/min. In a preferred embodiment, the injecting of the fluidicmaterial is provided at operating pressures and flow rates ranging fromabout 500 to 9,000 psi and 40 to 3,000 gallons/min. In a preferredembodiment, the injecting of the fluidic material is provided at reducedoperating pressures and flow rates during an end portion of the radialexpansion. In a preferred embodiment, the method further includes curingat least a portion of the fluidic material; and removing at least aportion of the cured fluidic material located within the tubular liner.In a preferred embodiment, the method further includes overlapping thetubular liner with an existing wellbore casing. In a preferredembodiment, the method further includes sealing the overlap between thetubular liner and the existing wellbore casing. In a preferredembodiment, the method further includes supporting the extruded tubularliner using the overlap with the existing wellbore casing. In apreferred embodiment, the method further includes testing the integrityof the seal in the overlap between the tubular liner and the existingwellbore casing. In a preferred embodiment, the method further includeslubricating the surface of the mandrel. In a preferred embodiment, themethod further includes absorbing shock. In a preferred embodiment, themethod further includes catching the mandrel upon the completion of theextruding. In a preferred embodiment, the method further includesexpanding the mandrel in a radial direction. In a preferred embodiment,the method further includes drilling out the mandrel. In a preferredembodiment, the method further includes supporting the mandrel withcoiled tubing. In a preferred embodiment, the wall thickness of thetubular member is variable. In a preferred embodiment, the mandrel iscoupled to a drillable shoe.

An apparatus has also been described that includes a support member, thesupport member including a first fluid passage; a mandrel coupled to thesupport member, the mandrel including: a second fluid passage; a tubularmember coupled to the mandrel; and a shoe coupled to the tubular liner,the shoe including a third fluid passage; and a drilling assemblycoupled to the shoe; wherein the first, second and third fluid passagesand the drilling assembly are operably coupled. In a preferredembodiment, the support member further includes: a pressure reliefpassage; and a flow control valve coupled to the first fluid passage andthe pressure relief passage. In a preferred embodiment, the supportmember further includes a shock absorber. In a preferred embodiment, thesupport member includes one or more sealing members adapted to preventforeign material from entering an interior region of the tubular member.In a preferred embodiment, the support member includes one or morestabilizers. In a preferred embodiment, the mandrel is expandable. In apreferred embodiment, the tubular member is fabricated from materialsselected from the group consisting of Oilfield Country Tubular Goods,automotive grade steel, plastic and chromium steel. In a preferredembodiment, the tubular member has inner and outer diameters rangingfrom about 0.75 to 47 inches and 1.05 to 48 inches, respectively. In apreferred embodiment, the tubular member has a plastic yield pointranging from about 40,000 to 135,000 psi. In a preferred embodiment, thetubular member includes one or more sealing members at an end portion.In a preferred embodiment, the tubular member includes one or morepressure relief holes at an end portion. In a preferred embodiment, thetubular member includes a catching member at an end portion for slowingdown movement of the mandrel. In a preferred embodiment, the supportmember comprises coiled tubing. In a preferred embodiment, at least aportion of the mandrel and shoe are drillable. In a preferredembodiment, the wall thickness of the tubular member in an area adjacentto the mandrel is less than the wall thickness of the tubular member inan area that is not adjacent to the mandrel. In a preferred embodiment,the apparatus further includes an expandible chamber. In a preferredembodiment, the expandible chamber is approximately cylindrical. In apreferred embodiment, the expandible chamber is approximately annular.

A method of forming an underground pipeline within an underground tunnelincluding at least a first tubular member and a second tubular member,the first tubular member having an inner diameter greater than an outerdiameter of the second tubular member, has also been described thatincludes positioning the first tubular member within the tunnel;positioning the second tubular member within the tunnel in anoverlapping relationship with the first tubular member; positioning amandrel and a drilling assembly within an interior region of the secondtubular member; injecting a fluidic material within the mandrel,drilling assembly and the second tubular member; extruding at least aportion of the second tubular member off of the mandrel into engagementwith the first tubular member; and drilling the tunnel. In a preferredembodiment, the injecting of the fluidic material is provided atoperating pressures ranging from about 500 to 9,000 psi. In a preferredembodiment, the injecting of the fluidic material is provided at reducedoperating pressures during a latter portion of the extruding. In apreferred embodiment, the method further includes sealing the interfacebetween the first and second tubular members. In a preferred embodiment,the method further includes supporting the extruded second tubularmember using the interface with the first tubular member. In a preferredembodiment, the method further includes lubricating the surface of themandrel. In a preferred embodiment, the method further includesabsorbing shock. In a preferred embodiment, the method further includesexpanding the mandrel in a radial direction. In a preferred embodiment,the method further include sealing the interface between the first andsecond tubular members. In a preferred embodiment, the method furtherincludes supporting the extruded second tubular member using the firsttubular member. In a preferred embodiment, the method further includestesting the integrity of the seal in the interface between the firsttubular member and the second tubular member. In a preferred embodiment,the method further includes catching the mandrel upon the completion ofthe extruding. In a preferred embodiment, the method further includesdrilling out the mandrel. In a preferred embodiment, the method furtherincludes supporting the mandrel with coiled tubing. In a preferredembodiment, the method further includes coupling the mandrel to adrillable shoe. In a preferred embodiment, the fluidic material isinjected into an expandible chamber. In a preferred embodiment, theexpandible chamber is substantially cylindrical. In a preferredembodiment, the expandible chamber is substantially annular. Anapparatus has also been described that includes a wellbore, the wellboreformed by the process of drilling the wellbore; and a tubular linerpositioned within the wellbore, the tubular liner formed by the processof extruding the tubular liner off of a mandrel while drilling thewellbore. In a preferred embodiment, the tubular liner is formed by theprocess of: placing the tubular liner and mandrel within the wellbore;and pressurizing an interior portion of the tubular liner. In apreferred embodiment, the interior portion of the tubular liner ispressurized at pressures ranging from about 500 to 9,000 psi. In apreferred embodiment, the -tubular liner is formed by the process of:placing the tubular liner and mandrel within the wellbore; andpressurizing an interior portion of the mandrel. In a preferredembodiment, the interior portion of the mandrel is pressurized atpressures ranging from about 500 to 9,000 psi. In a preferredembodiment, the apparatus further includes an annular body of a curedfluidic material coupled to the tubular liner. In a preferredembodiment, the annular body of a cured fluidic sealing material isformed by the process of: injecting a body of hardenable fluidic sealingmaterial into an annular region external of the tubular liner. In apreferred embodiment, the tubular liner overlaps with an existingwellbore casing. In a preferred embodiment, the apparatus furtherincludes a seal positioned in the overlap between the tubular liner andthe existing wellbore casing. In a preferred embodiment, the tubularliner is supported by the overlap with the existing wellbore casing. Ina preferred embodiment, the process of extruding the tubular linerincludes the pressurizing of an expandible chamber. In a preferredembodiment, the expandible chamber is substantially cylindrical. In apreferred embodiment, the expandible chamber is substantially annular.

A method of forming a wellbore casing in a wellbore has also beendescribed that includes drilling out the wellbore while forming thewellbore casing. In a preferred embodiment, the forming includes:expanding a tubular member in the radial direction. In a preferredembodiment, the expanding includes: displacing a mandrel relative to thetubular member. In a preferred embodiment, the displacing includes:expanding an expandible chamber. In a preferred embodiment, theexpandible chamber comprises a cylindrical chamber. In a preferredembodiment, the expandible chamber comprises an annular chamber.

Although illustrative embodiments of the invention have been shown anddescribed, a wide range of modification, changes and substitution iscontemplated in the foregoing disclosure. In some instances, somefeatures of the present invention may be employed without acorresponding use of the other features. Accordingly, it is appropriatethat the appended claims be construed broadly and in a manner consistentwith the scope of the invention.

What is claimed is:
 1. A wellhead, comprising: an outer casing; and aplurality of substantially concentric and overlapping inner casingscoupled to the outer casing; wherein an end portion of each inner casingis supported by contact pressure between an outer surface of the innercasing and an inner surface of the outer casing; wherein adjacent innercasings define an annulus therebetween; and wherein the end portion ofat least one of the inner casings coupled to the outer casing definesone or more radial passages.
 2. The wellhead of claim 1, wherein theouter casing has a yield strength ranging from about 40,000 to 135,000psi.
 3. The wellhead of claim 1, wherein the outer casing has a burststrength ranging from about 5,000 to 20,000 psi.
 4. The wellhead ofclaim 1, wherein the contact pressure between the inner casings and theouter casing ranges from about 500 to 10,000 psi.
 5. The wellhead ofclaim 1, wherein one or more of the inner casings include one or moresealing members that contact with an inner surface of the outer casing.6. The wellhead of claim 5, wherein the sealing members are selectedfrom the group consisting of rubber, lead, plastic, and epoxy.
 7. Thewellhead of claim 1, further comprising a Christmas tree coupled to theouter casing.
 8. The wellhead of claim 1, further comprising a drillingspool coupled to the outer casing.
 9. The wellhead of claim 1, whereinat least one of the inner casings is a production casing.
 10. Awellhead, comprising: an outer casing at least partially positionedwithin a wellbore; and a plurality of substantially concentric innercasings coupled to the interior surface of the outer casing by theprocess of expanding an end portion of one or more of the inner casingsinto contact with at least a portion of the interior surface of theouter casing; wherein adjacent inner casings define an annulustherebetween; and wherein the end portion of at least one of the innercasings coupled to the outer casing defines one or more radial passages.11. The wellhead of claim 10, wherein the inner casings are expanded byextruding the inner casings off of a mandrel.
 12. The wellhead of claim11, wherein the inner casings are expanded by the process of: placingthe inner casing and a mandrel within the wellbore; and pressurizing aninterior portion of the inner casing.
 13. The wellhead of claim 12,wherein during the pressurizing, the interior portion of the innercasing is fluidicly isolated from an exterior portion of the innercasing.
 14. The wellhead of claim 13, wherein the interior portion ofthe inner casing is pressurized at pressures ranging from about 500 to9,000 psi.
 15. The wellhead of claim 10, further comprising one or moreseals positioned in the interface between the inner casings and theouter casing.
 16. The wellhead of claim 10, wherein the inner casingsare supported by their contact with the outer casing.
 17. An apparatus,comprising: an outer tubular member; and a plurality of substantiallyconcentric and overlapping inner tubular members coupled to the outertubular member; wherein an end portion of each inner tubular member issupported by contact pressure between an outer surface of the innercasing and an inner surface of the outer inner tubular member; whereinadjacent inner casings define an annulus therebetween; and wherein theend portion of at least one of the inner casings coupled to the outercasing defines one or more radial passages.
 18. The apparatus of claim17, wherein the outer tubular member has a yield strength ranging fromabout 40,000 to 135,000 psi.
 19. The apparatus of claim 17, wherein theouter tubular member has a burst strength ranging from about 5,000 to20,000 psi.
 20. The apparatus of claim 17, wherein the contact pressurebetween the inner tubular members and the outer tubular member rangesfrom about 500 to 10,000 psi.
 21. The apparatus of claim 17, wherein onemore of the inner tubular members include one or more sealing membersthat contact with an inner surface of the outer tubular member.
 22. Theapparatus of claim 21, wherein the sealing members are selected from thegroup consisting of rubber, lead, plastic, and epoxy.
 23. An apparatus,comprising: an outer tubular member; and a plurality of substantiallyconcentric inner tubular members coupled to the interior surface of theouter tubular member by the process of expanding an end portion of oneor more of the inner tubular members into contact with at least aportion of the interior surface of the outer tubular member; whereinadjacent inner casings define an annulus therebetween; and wherein theend portion of at least one of the inner casings coupled to the outercasing defines one or more radial passages.
 24. The apparatus of claim23, wherein the inner tubular members are expanded by extruding theinner tubular members off of a mandrel.
 25. The apparatus of claim 24,wherein the inner tubular members are expanded by the process of:placing the inner tubular members and a mandrel within the outer tubularmember; and pressurizing an interior portion of the inner casing. 26.The apparatus of claim 25, wherein during the pressurizing, the interiorportion of the inner tubular member is fluidicly isolated from anexterior portion of the inner tubular member.
 27. The apparatus of claim25, wherein the interior portion of the inner tubular member ispressurized at pressures ranging from about 500 to 9,000 psi.
 28. Theapparatus of claim 23, further comprising one or more seals positionedin the interface between the inner tubular members and the outer tubularmember.
 29. The apparatus of claim 23, wherein the inner tubular membersare supported by their contact with the outer tubular member.